NERC Supplemental INfo. to Petition for approval of Proposed PRC-025-1

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation

)
)

Docket No. RM13-19-000

SUPPLEMENTAL IINFORMATION TO THE PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD PRC-025-1
(GENERATOR RELAY LOADABILITY)
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
William H. Edwards
Counsel
Brady A. Walker
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
December 17, 2013

TABLE OF CONTENTS
I.

NOTICES AND COMMUNICATIONS ................................................................................ 3

II.

JUSTIFICATION FOR APPROVAL..................................................................................... 3
A.

Improvements Reflected in proposed Reliability Standard PRC-023-3 .......................... 3

B.

Enforceability of proposed Reliability Standard PRC-023-3 ........................................... 5

III. MINORITY UNIT AUXILIARY TRANSFORMER ISSUE ................................................ 6
IV. CONCLUSION ....................................................................................................................... 6

Exhibit A

Proposed Reliability Standard PRC-023-3

Exhibit B

Implementation Plan for Proposed Reliability Standard PRC-023-3

Exhibit C

Order No. 672 Criteria for Proposed Reliability Standard PRC-023-3

Exhibit D

Summary of Development History and Complete Record of Development

Exhibit E

Standard Drafting Team Report: Unit Auxiliary Transformer Issue

i

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation

)
)

Docket No. RM13-19-000

SUPPLEMENTAL INFORMATION TO THE PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD PRC-025-1
(GENERATOR RELAY LOADABILITY)
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”)1 and Section 39.52 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”)3 hereby submits proposed Reliability
Standard PRC-023-3—Transmission Relay Loadability for Commission as a supplement to the
petition for approval of proposed Reliability Standard PRC-025-1—Generator Relay Loadability.
NERC requests that the Commission approve proposed Reliability Standard PRC-023-3 (Exhibit
A) concurrently with proposed Reliability Standard PRC-025-1 and find that the proposed
Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the
public interest.4 NERC also requests approval of the associated implementation plan (Exhibit B)
and retirement of the currently effective Reliability Standard PRC-023-2, as detailed in this
supplement.
As noted in the petition, during the development of proposed Reliability Standard PRC025-1, clarifying changes to Reliability Standard PRC-023-2 were identified by the standard
drafting team as necessary to establish a bright-line distinction between the applicability of load1

16 U.S.C. § 824o (2006).
18 C.F.R. § 39.5 (2013).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, available at http://www.nerc.com/files/Glossary_of_Terms.pdf
2

1

responsive protective relays in the transmission and generator relay loadability Reliability
Standards. As a result, a supplemental Standard Authorization Request was approved by the
Standards Committee at its January 16-17, 2013 meeting to authorize the standard drafting team
to make the corresponding changes.
In the previously filed PRC-025-1 petition, NERC requested the Commission delay its
approval of proposed Reliability Standard PRC-025-1 until proposed Reliability Standard PRC023-3 – Transmission Relay Loadability was submitted in a supplemental filing to the
Commission. Proposed PRC-023-3 was approved by the NERC Board of Trustees at its
November 7, 2013 meeting and is submitted here as a supplement to the pending petition for
approval of proposed Reliability Standard PRC-025-1. To preserve consistency between
proposed Reliability Standards PRC-025 and PRC-023, NERC has requested the Commission
take concurrent action on the proposed Reliability Standards PRC-025-1 and PRC-023-3.
As required by Section 39.5(a)5 of the Commission’s regulations, this supplement
presents the technical basis and purpose of proposed Reliability Standard PRC-023-3, a summary
of the development history (Exhibit D), and a demonstration that the proposed Reliability
Standard meets the criteria identified by the Commission in Order No. 6726 (Exhibit C).

5

18 C.F.R. § 39.5(a) (2013).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
6

2

I.

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

following:7
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
William H. Edwards*
Counsel
Brady A. Walker*
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
II.

Mark G. Lauby*
Vice President and Director of Standards
Howard Gugel*
Director of Standards Development
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
[email protected]

JUSTIFICATION FOR APPROVAL
As discussed in detail in Exhibit C, proposed Reliability Standard PRC-023-3 satisfies

the Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest.
A.

Improvements Reflected in proposed Reliability Standard PRC-023-3

During the development of proposed Reliability Standard PRC-025-1, the standard
drafting team and industry stakeholders identified the potential for compliance overlap between
Reliability Standard PRC-023-2 and proposed Reliability Standard PRC-025-1. The concern
was that the two Reliability Standards would overlap with regard to the application of loadPersons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully requests
a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2013), to allow the inclusion of more
than two persons on the service list in this proceeding.
7

3

responsive protective relays on transmission lines that connect the generating plant or generating
units to the Transmission System. Proposed Reliability Standard PRC-025-1 introduces criteria
for relays applied at the terminals of such lines. Requirement R1, Criterion 6 of Reliability
Standard PRC-023-2, however, requires entities to “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 aggregated generation nameplate capability.” The potential compliance overlap
could result in a finding of a non-compliance with both Reliability Standards unless appropriate
clarifying revisions are made.
To properly align proposed Reliability Standard PRC-025-1, the standard drafting team
undertook an effort to revise Reliability Standard PRC-023-2. Following is an explanation of the
revisions included in proposed Reliability Standard PRC-023-3.
Requirement R1, Criterion 6 of Reliability Standard PRC-023-2 was removed and the
applicability section was revised to exclude “Elements that connect the GSU transformer(s) to
the Transmission system that are used exclusively to export energy directly from a Bulk Electric
System generating unit or generating plant.” These changes avoid overlap with the
Requirements in proposed Reliability Standard PRC-025-1 that apply to these Facilities.
Proposed Reliability Standard PRC-025-1 was developed to include relay loadability
requirements for all load responsive protective relays applied at the terminals of generators and
GSU transformers. As such, section 2.4 of Attachment A of Reliability Standard PRC-023-2—
which addressed applicability to generator protection relays—was removed in proposed
Reliability Standard PRC-023-3 to avoid overlap between the two proposed Reliability
Standards.

4

The applicability sections for the two proposed Reliability Standards are based on the
location where the relays are applied and are independent of the intended protection function.
Basing applicability on the physical location where the relay is applied provides the following
advantages:
(i)

Facilitates the establishment of generator relay loadability requirements based on
the physics associated with increased generator output during stressed system
conditions.

(ii)

Avoids ambiguity as to whether the intended protection function is for the
generating unit or the Transmission System. For example, a relay may be applied
at the terminals of a generator to provide backup protection for the GSU
transformer, but because the relay setting must “over-reach” the GSU transformer
terminals, the relay inherently provides backup protection for the high-voltage bus
and close-in portions of transmission lines.

(iii)

Provides clear division of applicability between the Generator and Transmission
Relay Loadability Reliability Standards based on the physical location,
independent of the entity that owns the relay.

The applicability requirements in proposed Reliability Standard PRC-025-1 and
corresponding revisions to the applicability requirements in proposed Reliability Standard PRC023-3 address the Commission’s concern that all generator and GSU transformer load-responsive
protective relays are subject to appropriate requirements in a Reliability Standard.
B.

Enforceability of proposed Reliability Standard PRC-023-3

The proposed Reliability Standard PRC-023-3 contains Measures that support the
Requirements by clearly identifying acceptable evidence of compliance and how the

5

Requirements will be enforced. The Implementation Plan also discusses the documentation
necessary to comply with the proposed Reliability Standard. The VSLs provide further guidance
on the processes through which NERC will enforce the Requirements of the proposed Reliability
Standard. The VRFs and VSLs for the proposed Reliability Standard comport with NERC and
Commission guidelines related to their assignment. The VSLs have been developed based on the
situations an auditor may encounter during a compliance audit.
III.

MINORITY UNIT AUXILIARY TRANSFORMER ISSUE
As discussed in the petition for proposed Reliability Standard PRC-025-1, minority

comments raised questions as to whether the low-voltage side relays of unit auxiliary
transformers (“UAT”) should be included in the proposed Reliability Standard. The standard
drafting team has studied this issue and determined there is no adverse reliability impact created
by the Reliability Standard as proposed. Based on the standard drafting team’s findings, no
changes to proposed Reliability Standard PRC-025-1 regarding the addition of low-voltage side
relays are necessary at this time. However, NERC staff will implement a recommendation by
the standard drafting team to monitor UAT performance through its customary data collection
processes.
The standard drafting team has prepared a report on this issue; it is attached to this
petition as Exhibit E.
IV.

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

approve proposed Reliability Standard PRC-023-3 and associated elements included in
Exhibit A, effective as proposed herein;

•

approve the Implementation Plan included in Exhibit B; and

•

approve the retirement of Reliability Standard PRC-023-2, effective as proposed herein.

6

Respectfully submitted,
/s/ Brady A. Walker
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
William H. Edwards
Counsel
Brady A. Walker
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: December 17, 2013

7

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 17th day of December, 2013.
/s/ Brady A. Walker
Brady A. Walker
Counsel for North American Electric
Reliability Corporation

Exhibit A
Proposed Reliability Standard

Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title:

Transmission Relay Loadability

2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinator
4.2. Circuits:
4.2.1 Circuits Subject to Requirements R1 – R5:
4.2.1.1 Transmission lines operated at 200 kV and above, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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
Requirement 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, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.

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Standard PRC-023-3 — Transmission Relay Loadability
4.2.2.2 Transmission lines operated below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES, except
Elements that connect the GSU transformer(s) to the Transmission system
that are used exclusively to export energy directly from a BES generating
unit or generating plant. Elements may also supply generating plant loads.
5. Effective Dates: See Implementation Plan.
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 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, 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. Not used.

1

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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

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 capability2.

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 3.

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.

2

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.
3

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.

3 of 14

Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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)

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Standard PRC-023-3 — 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 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 PRC-023-3, 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)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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:

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Standard PRC-023-3 — Transmission Relay Loadability
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 Requirement 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 Requirement 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 Enforcement Authority 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.

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Standard PRC-023-3 — Transmission Relay Loadability

2.
Requirement

R1

Violation Severity Levels:
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 BES 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.

R2

R3

N/A

N/A

N/A

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

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 7, 8, 9,
12, or 13 did not use the calculated
circuit capability as the Facility
Rating of the circuit.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

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.

8 of 14

Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

High
months or more 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 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)

Severe
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

9 of 14

Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

10 of 14

Standard PRC-023-3 — 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

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

November 7,
2013

Adopted by NERC Board of Trustees

Supplemental SAR
to Clarify
applicability for
consistency with
PRC-025-1 and
other minor
corrections.

11 of 14

Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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. Not used.
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.

12 of 14

Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 Bulk Electric System.

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 Interconnection Reliability Operating Limit (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 4 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.

4

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

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Standard PRC-023-3 — 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.

14 of 14

Standard PRC-023-23 — Transmission Relay Loadability
A. Introduction
1. Title:

Transmission Relay Loadability

2. Number:

PRC-023-23

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 OwnersOwner with load-responsive phase protection systems as
described in PRC-023-23 - Attachment A, applied toat the terminals of the circuits
defined in 4.2.1 (Circuits Subject to Requirements R1 – R5).
4.1.2 Generator OwnersOwner with load-responsive phase protection systems as described
in PRC-023-23 - Attachment A, applied toat the terminals of the circuits defined in
4.2.1 (Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution ProvidersProvider with load-responsive phase protection systems as
described in PRC-023-23 - Attachment A, applied toat the terminals of the circuits
defined in 4.2.1 (Circuits Subject to Requirements R1 – R5), provided those circuits
have bi-directional flow capabilities.
4.1.4 Planning CoordinatorsCoordinator
4.2. Circuits :
4.2.1 Circuits Subject to Requirements R1 – R5:
4.2.1.1 Transmission lines operated at 200 kV and above, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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
Requirement 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, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.

1 of 18

Standard PRC-023-23 — Transmission Relay Loadability
4.2.2.2 Transmission lines operated below100below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES
5.

Effective Dates
4.2.2.2 The effective dates of, except Elements that connect the requirements in the
PRC-023-2 standard correspondingGSU transformer(s) to the applicable
Functional Entities and circuitsTransmission system that are summarized in
the following table:used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply generating
plant loads.

2 of 18

Standard PRC-023-23 — Transmission Relay Loadability
Effective Date
Applicability

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where
No Regulatory
Approval is Required

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

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

•

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 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
(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

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

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

Requirement

R1

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.

3 of 18

Standard PRC-023-23 — Transmission Relay Loadability
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
Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement R6

R2 and R3

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where
No Regulatory
Approval is Required

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

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

First day of the first
calendar quarter after
applicable regulatory
approvals

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

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

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

4 of 18

Standard PRC-023-23 — Transmission Relay Loadability
Effective Date
Applicability

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where
No Regulatory
Approval is Required

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

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

R5

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

R6

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

Requirement

5 of 18

Standard PRC-023-23 — Transmission Relay Loadability
5. Effective Dates: See Implementation Plan.
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 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.
6. Not used.
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.
2

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.

6 of 18

Standard PRC-023-23 — 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.

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.

3

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.

7 of 18

Standard PRC-023-23 — Transmission Relay Loadability
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 PRC-023-3, 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-023-23 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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.
6.2
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)

8 of 18

Standard PRC-023-23 — 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 PRC-023-3, 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)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
•1.1.

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
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority. ” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.

1.2. Data Retention
The Transmission Owner, Generator Owner, Distribution Provider and Planning
Coordinator shall keep data or evidence to show compliance as identified below unless

9 of 18

Standard PRC-023-23 — Transmission Relay Loadability
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 Requirement 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 Requirement 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 MonitorEnforcement Authority 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.

10 of 18

Standard PRC-023-23 — Transmission Relay Loadability

2.
Requirement

R1

Violation Severity Levels:
Lower

Moderate

N/A

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 SystemBES 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.

R2

R3

N/A

N/A

N/A

N/A

13

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

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.

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

13

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.

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

13

High
months or more 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 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)

Severe
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

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

13

Standard PRC-023-23 — 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

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

November 7,
2013

Adopted by NERC Board of Trustees

17

Supplemental SAR
to Clarify
applicability for
consistency with
PRC-025-1 and
other minor
corrections.

Standard PRC-023-23 — Transmission Relay Loadability
PRC-023-3 — 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.
2.4. Not used.
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.

17

Standard PRC-023-23 — Transmission Relay Loadability
PRC-023-3 — 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 BESBulk Electric System.

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,Interconnection Reliability Operating Limit
(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.

5

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

17

Standard PRC-023-23 — 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.
B6.

17

Exhibit B
Implementation Plan

Implementation Plan

PRC-023-3 – Transmission Relay Loadability
Project 2010-13.2 Phase II Relay Loadability
Requested Approvals

•

PRC-023-3 – Transmission Relay Loadability

Requested Retirements

•

PRC-023-2 – Transmission Relay Loadability

Prerequisite Approvals

•

PRC-025-1 – Generator Relay Loadability*
*A supplemental SAR was approved by the Standards Committee at their January 16-17, 2013 meeting to
authorize the drafting team to make changes to PRC-023-2 to comport with the proposed draft PRC-0251 – Generator Relay Loadability in order to establish a bright line between the applicability of loadresponsive protective relays in the current transmission and the proposed generator relay loadability
standards.

Revisions to Defined Terms in the NERC Glossary

•

None

Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is
no bright line to clearly distinguish which load-responsive protective relays pertain to the existing PRC-023-2 –
Transmission Relay Loadability standard, effective in the United States on July 1, 2012, and the proposed PRC025-1 – Generator Relay Loadability standard. To resolve this concern, the drafting team proposed to modify
the applicability section of PRC-023-2. The standard drafting team clarified, for each functional entity, the
applicability of PRC-023-2 by tying applicability to the terminal the load-responsive protective relay that it is
connected to within the Transmission system.

General Considerations

It is expected that the implementation period for PRC-023-2 will have been achieved, in part, by the time PRC023-3 is adopted by the NERC Board of Trustees and by the time of other approvals by applicable

governmental authorities. The proposed PRC-023-3 Implementation Plan now reflects specific milestone dates
that are known time periods consistent with PRC-023-2.
Applicable Entities

•

Distribution Provider

•

Generator Owner

•

Planning Coordinator

•

Transmission Owner

Effective Date
New Standard

PRC-023-3

First day of the first calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the
first day of the first calendar quarter beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.

Standards for Retirement

PRC-023-2

Midnight of the day immediately prior to the Effective Date of PRC-023-3 –
Transmission Relay Loadability in the particular jurisdiction in which the new
standard is becoming effective, except Requirement R1, Criterion 6 which will
remain in force until the effective date of PRC-025-1.

Implementation Plan for Definitions

No definitions are proposed as a part of this standard.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

2

Implementation Plan for PRC-023-3, Requirements R1 through R6

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to
this standard shall be 100% compliant on the following dates:
Implementation Date
Requirement

Applicability

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on transmission lines operating
at 200 kV and above and transformers
with low voltage terminals connected at
200 kV and above, except as noted
below.

R1

•

•

For supervisory elements as
described in PRC-023-3 - Attachment
A, Section 1.6

For switch-on-to-fault schemes as
described in PRC-023-3 - Attachment
A, Section 1.3

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

The later of July 1,
2014 or first day of the
first calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

3

Implementation Date
Requirement

R1
(continued)

R2 and R3

Applicability

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

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on transmission lines operating
at 200 kV and above and transformers
with low voltage terminals connected at
200 kV and above

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

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 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

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 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

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

4

Implementation Date
Requirement

R2 and R3
continued

R4

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on 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 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

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 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 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 Board of
Trustees adoption, or
First day of the first
as otherwise made
calendar quarter six
months after applicable effective pursuant to
the laws applicable to
regulatory approvals
such ERO
governmental
authorities

Applicability

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

5

Implementation Date
Requirement

R5

R6
(including
parts 6.1 and
6.2)

Applicability

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

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 Owner,
and Distribution Providers must comply
with Requirements R1 through R5

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Later of January 1,
2014 or the first day of
the first calendar
quarter after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

6

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is
implemented. If the drafting team is recommending revisions, those changes are identified by the “Proposed Replacement” column.
Already Approved Standard
PRC-023-2
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

Proposed Replacement
PRC-023-3
4.1. Functional Entity
4.1.1 Transmission Owner with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5), provided those circuits have bi-directional flow
capabilities.
4.1.4 Planning Coordinator

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1, Functional Entity creates a bright line between those load-responsive
protective relays that are applicable to PRC-023-3 – Transmission Relay Loadability and the proposed PRC-025-1 – Generator Relay Loadability.
This is evident by the minor changes to the Applicability text to distinguish the applicability of the relays by which “terminal” the load-responsive
protective relay is connected to within the Transmission system. Applicability is established by ownership of the load-responsive protective
relays, not the Facilities.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

7

Already Approved Standard

Proposed Replacement

PRC-023-2
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.

PRC-023-3
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above, except
Elements that connect the GSU transformer(s) to the Transmission
system that are used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply
generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the
Planning Coordinator in accordance with Requirement 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
Requirement 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
Requirement 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 Requirement R6.

4.2.2 Circuits Subject to Requirement R6

4.2.2 Circuits Subject to Requirement R6

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

8

Already Approved Standard

Proposed Replacement

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 below 100 kV and transformers
with low voltage terminals connected below 100 kV that are part of the
BES

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, except Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant. Elements may also
supply generating plant loads.
4.2.2.2 Transmission lines operated below 100 kV and transformers
with low voltage terminals connected below 100 kV that are part of the
BES, except Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant. Elements may also
supply generating plant loads.

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1 Facilities, creates a bright line between those Facilities that are applicable
to PRC-023-3 – Transmission Relay Loadability and those Facilities in the proposed PRC-025-1 – Generator Relay Loadability. This is achieved by
excluding Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a
BES generating unit or generating plant while allowing these Elements to also supply generating plant loads. Plant loads may include situations
like pumped storage facilities where the generating plant also serves as a load for pumping.
The above applicability items for Section 4.2 “Circuits” that are subject to the standard were modified to exclude those Elements that connect
the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating
plant. Elements may also supply generating plant loads. The added text reads: “except Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Elements may also supply
generating plant loads” and is found in Sections 4.2.1.1, 4.2.2.1, and 4.2.2.2. This eliminates an overlap with PRC-025-1 and places the
performance for lines and transformers that are used exclusively to export energy directly from a BES generating unit or generating plant to the
network under the proposed PRC-025-1 with the understanding that these Elements may also supply generating plant loads.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

9

Already Approved Standard
PRC-023-2 (Retirement)
R1, Criterion 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.”

Proposed Replacement
PRC-025-1 (New)
New Requirement
R1. Each Generator Owner, Transmission Owner, and Distribution
Provider shall apply settings that are in accordance with PRC-025-1 –
Attachment 1: Relay Settings, on each load-responsive protective relay
while maintaining reliable fault protection. [Violation Risk Factor: High]
[Time Horizon: Long-Term Planning]
*Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation
Criteria, Options 14 through 19. (See standard for details)

Notes: The Transmission Owner and Distribution Provider were added to the Applicability of the proposed PRC-025-1 and excluded Elements
that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads. Therefore, Requirement R1, Criterion 6 has been removed from the proposed
standard PRC-023-3 because this criterion is now replaced (i.e., superseded) by the proposed PRC-025-1 – Generator Relay Loadability standard,
Requirement R1 and its Attachment 1: Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria, Options 14 through 19.
Applicability concerning generation Facilities is now addressed in the proposed PRC-025-1. Although, Requirement R1, Criterion 6 is not shown in
the proposed PRC-023-3, it remains auditable while each entity assures its compliance with the proposed PRC-025-1 criteria according to the
provided Implementation Plan(s).
PRC-023-2 (Retirement)
R1, Attachment A, exclusion 2.4. “Generator protection relays that are
susceptible to load.”

None.

Notes: This exclusion has been superseded by the proposed PRC-025-1 standard that pertains to these relays. The proposed PRC-023-3 standard
does not include any criteria that are relevant to generator protection relays. The proposed PRC-025-1 standard establishes specific criteria for
generator load-responsive protective relays, and renders this exclusion unnecessary.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

10

Exhibit C
Order No. 672 Criteria

Exhibit C—Order No. 672 Criteria—Proposed Reliability Standard PRC-023-3—Transmission
Relay Loadability
In Order No. 672,1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1.

Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal.2
The proposed standard achieves the specific reliability goal of ensuring that Reliability

Standards are clear and unambiguous in their Applicability. This is accomplished by inserting
clarifying language regarding the applicability of proposed Reliability Standard PRC-023-3 and
thereby strengthening the previously submitted and currently pending proposed Reliability
Standard PRC-025-1 as a response to Commission directives.
2.

Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply.3

1

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.
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.
3
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 Reliability Standard is clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. The proposed Reliability
Standard applies to Distribution Providers, Generator Owners, Planning Coordinators, and
Transmission Owners and clearly articulates the actions that such entities must take to comply
with the proposed Reliability Standard.
3.

A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the

proposed Reliability Standard comport with NERC and Commission guidelines related to their
assignment. The VRFs and VSLs in the proposed Reliability Standard have not been revised; the
VRFs and VSLs contained in Reliability Standard PRC-023-25 will remain in effect upon
approval of proposed Reliability Standard PRC-023-3.
4.

A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and non
preferential manner.6
The proposed Reliability Standard contains Measures that support each Requirement by

clearly identifying what is required and how the Requirement will be enforced. The Measures in
the proposed Reliability Standard have not been revised; the Measures contained in Reliability

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.
4
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.
5
Available at: http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=PRC-0232&title=Transmission%20Relay%20Loadability&jurisdiction=United%20States
6
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.

Standard PRC-023-27 will remain in effect upon approval of proposed Reliability Standard PRC023-3.
5.

Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design.8
The proposed Reliability Standard achieves its reliability goals effectively and efficiently

in accordance with Order No. 672. With a clear distinction between proposed Reliability
Standards PRC-023-3 and PRC-025-1, Entities are now able to effectively implement both
Reliability Standards, in accordance with Commission directives, without the risk of inconsistent
compliance and enforcement procedures.
6.

Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability.9
The proposed Reliability Standard does not reflect a “lowest common denominator”

approach. To the contrary, the proposed standard represents a significant improvement over the
previous version as described herein. By providing clarity in Applicability, the risk of redundant
compliance violations is significantly decreased making the proposed Reliability Standard much
7

Available at: http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=PRC-0232&title=Transmission%20Relay%20Loadability&jurisdiction=United%20States
8
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.
9
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice — the socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect 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.

more effectively enforceable and understandable to industry. These revisions also support the
Commission’s directives that lead to the development of proposed Reliability Standard PRC025-1, which is currently pending before the Commission.
7.

Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard.10
The proposed Reliability Standard applies throughout North America and does not favor

one geographic area or regional model.
8.

Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability.11
Proposed Reliability Standard PRC-023-3 has no undue negative impact on competition.

The proposed Reliability Standard requires the same performance by each of the applicable
Functional Entities.
The proposed Reliability Standard does not unreasonably restrict the available
transmission capability or limit use of the Bulk-Power System in a preferential manner. The

10

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.
11

Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over another.

Requirements in the proposed Reliability Standard have been clarified to further enable Entities
to meet important reliability goals.
9.

The implementation time for the proposed Reliability Standard is reasonable.12
The proposed effective dates for the standard are just and reasonable and appropriately

balance the urgency in the need to implement the standards against the reasonableness of the
time allowed for those who must comply to develop necessary procedures, software, facilities,
staffing or other relevant capability. This will allow applicable entities adequate time to ensure
compliance with the Requirements. The proposed effective dates are explained in the proposed
Implementation Plan, attached as Exhibit B.
10.

The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process.13
The proposed Reliability Standard was developed in accordance with NERC’s

Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Exhibit D includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the proposed Reliability Standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the standard drafting team
were properly noticed and open to the public. The initial and recirculation ballots both achieved

12

Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.
13
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 FERC.

a quorum and exceeded the required ballot pool approval levels.
11.

NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.14
NERC has identified no competing public interests regarding the request for approval of

this proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12.

Proposed Reliability Standards must consider any other appropriate factors.15
No other negative factors relevant to whether the proposed Reliability Standard is just

and reasonable were identified.

14

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.
15
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.

accordance with the Commission-approved Reliability Standard development
process.11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Exhibit D includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the proposed Reliability Standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the standard drafting team
were properly noticed and open to the public. The initial and recirculation ballots both achieved
a quorum and exceeded the required ballot pool approval levels.
11.

NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of

this proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12.

Proposed Reliability Standards must consider any other appropriate factors.13
No other negative factors relevant to whether the proposed Reliability Standard is just

and reasonable were identified.

11

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 FERC.
12
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.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we will
consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.

Exhibit D
Summary of Development History and Complete Record of Development

Exhibit D—Summary of the Reliability Standard Development Proceeding and Complete
Record of Development of Proposed Reliability Standard PRC-023-3—Transmission Relay
Loadability
The development record for proposed Reliability Standard EOP-010-1 is summarized
below.
I.

Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give

“due weight” to the technical expertise of the ERO.1 The technical expertise of the ERO is
derived from the standard drafting team. For this project, the standard drafting team consisted of
industry experts, all with a diverse set of experiences.
II.

Standard Development History
A. Standard Authorization Request Development
A supplemental Standard Authorization Request (“SAR”) to revise Reliability Standard

PRC-023-2 was submitted on November 30, 2013 and approved by the Standards Committee
(“SC”) on January 18, 2013.
The supplemental SAR was posted for a 45-day public comment period from January 25,
2013 through March 11, 2013. There were 20 sets of responses, including comments from
approximately 89 individuals from approximately 54 companies representing 9 of the 10
Industry Segments. The standard drafting team made no changes to the supplemental SAR after
considering comments submitted.
B. First Posting
Proposed Reliability Standard PRC-023-3 was posted for a 30-day public comment
period from April 25, 2013 through May 24, 2013. There were 51 sets of responses, including

1

Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2006).

comments from approximately 166 individuals from approximately 92 companies representing 9
of the 10 Industry Segments.
The standard drafting team considered stakeholder comments and made the following
changes to proposed Reliability Standard PRC-023-3 based on those comments:
The most significant change was the removal of the previously proposed Requirements R7
and R8 which applied to the generator interconnection Facility and generator step-up
transformer applicable to the Distribution Provider and Transmission Owner. With this
change the standard drafting team added the Distribution Provider and Transmission Owner
to the applicability of proposed Reliability Standard PRC-025-1 and removed the
applicability of those lines and transformers that are used exclusively to export energy
directly from a BES generating unit or generating plant to the network from proposed
Reliability Standard PRC-023-3. This change establishes a bright line distinction between
the two Reliability Standards.
The following changes were made to the Applicability section:
o Removed references to Requirements R7 and R8
o Added the exception to sections 4.2.1.1, 4.2.2.1, and 4.2.2.2 to exclude lines and
transformers that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network
o Removed the sections 4.2.3 and 4.2.4
The following changes were made to the Requirements section:
o Requirement R1, criterion 6 was removed to comport with the elimination of
addressing load-responsive protective relays on lines and transformers that are used
exclusively to export energy directly from a BES generating unit or generating plant
to the network
The following changes were made to the Measures section:
o Removed the proposed Requirement R7
o Removed the proposed Requirement R8
The following changes were made to the Compliance section:
o Removed references to Requirements R7 and R8
The following changes were made to the Violation Severity Levels:
o Removed Requirements R7 and R8
The following change was made to Attachment A:
o Revised criterion 2.4 as “Note Used” since it is no longer needed
The following change was made to Attachment C:
o Removed due to the removal of Requirements R7 and R8

The following changes were made to the Implementation Plan:

o Updated to reflect the transition of PRC-023-3 Requirement R1, Criterion 6 to the
proposed criterion in proposed Reliability Standard PRC-025-1

The following changes were made to the VRF/VSL Justifications:
o References to Requirement R1, Criterion 6 were removed
C. Second Posting
Proposed Reliability Standard PRC-023-3 was posted for a 45-day public comment
period from June 20, 2013 through August 8, 2013. There were 27 sets of responses, including
comments from approximately 90 individuals from approximately 76 companies representing 9
of the 10 Industry Segments.
The standard drafting team considered stakeholder comments and made the following
changes to proposed Reliability Standard PRC-023-3 based on those comments:
In the Applicability section, Sections 4.2.1.1, 4.2.2.1, and 4.2.2.2 were revised to clarify
the applicability by removing “except lines that are used exclusively to export energy
directly from a Bulk Electric System (BES) generating unit or generating plant to the
network” and replacing it with “except Elements that connect the GSU transformer(s) to
the Transmission system that are used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply generating plant loads.”
In the Implementation Plan, the phrase “load-responsive phase protection systems on”
was inserted on Requirements R1, R2, and R3 Applicability of the Implementation Plan
to clarify that the “Applicability” column is referring to the ownership of the relays
applied on transmission lines and not the ownership of the line. Requirement R6 was
clarified that it includes Parts 6.1 and 6.2.
D. Initial Ballot
Proposed Reliability Standard PRC-023-3 was posted for an initial ballot period on July
26, 2013 through August 8, 2013. The proposed Reliability Standard received a quorum of
80.05% and an approval rating of 93%.
E. Final Ballot

Proposed Reliability Standard PRC-023-3 was posted for a 10-day final ballot period on
September 4, 2013 through September 13, 2013. The proposed Reliability Standard received a
quorum of 85.93% and an approval rating of 90.83%.
F. Board of Trustees Approval
Proposed Reliability Standard PRC-023-3 was approved by the NERC Board of Trustees
on November 7, 2013.

Project 2010-13.2 Phase 2 Relay Loadability: Generation
Related Files

Status:  
PRC‐023‐3 was adopted by the NERC Board of Trustees on November 7, 2013.

PRC-025‐1 was adopted by the NERC Board of Trustees on August 15, 2013. 

Background:
The March 18, 2010, FERC Order No. 733, approved Reliability Standard PRC-023-1 – Transmission Relay Loadability.
In this Order, FERC directed NERC to address three areas of relay loadability that include modifications to the
approved PRC-023-1, developing a new Reliability Standard to address three areas of relay loadability that include
modifications to the approved PRC-023-1, developing a new Reliability Standard to address generator protective relay
loadability, and another Reliability Standard to address the operation of protective relays due to power swings. This
project’s SAR addresses these directives and establishes a three-phased approach to standard development.
Phase 2 is focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay Loadability, to address
generator protective relay loadability. This Reliability Standard establishes requirements for the Generator Operator
functional entity to set protective relays at a level such that generating units do not trip during system disturbances
that are not damaging to the generator thereby unnecessarily removing the generator from service.
Phase 1 was focused on making the specific modifications to PRC-023-1 and was completed in the approved PRC023-2 Reliability Standard, which became mandatory on July 1, 2012. Phase 3, which will follow this project, will
focus on developing requirements that address protective relay operations due to stable power swings.
Purpose/Industry Need:
During analysis of many of the major disturbances in the last 25 years on the North American interconnected power
system, generators have been found to have tripped for conditions that did not apparently pose a direct risk to those
generators and associated equipment within the time period where the tripping occurred. This unnecessary tripping
has often been evaluated to have extended the scope and/or duration of that disturbance. This was noted, in detail,
to be a serious issue in the August 2003 “blackout’ in the northeastern North American continent.
During the recoverable phase of a disturbance, the disturbance may exhibit a “voltage disturbance” behavior pattern,
where system voltage is widely depressed. In order to support the system during this phase of a disturbance, this
standard establishes criteria for setting load-responsive relays such that individual generators may provide Reactive
Power within their dynamic capability during transient time periods to help the system recover from that voltage
disturbance. Premature or unnecessary tripping of generators during this period can deepen the severity of the
voltage disturbance due to removal of dynamic Reactive Power, and change the character of the disturbance such
that it is less recoverable.

Draft 

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Standard Authorization Request Form
Supplemental SAR for Project 2010-13.2 Relay Loadability Order 733 Phase 2 (Relay Loadability:
Generation)
Request Date

11/30/2012

SC Approval Date

01/18/2013

Revised Date

SAR Requester Information

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

Name
Howard Gugel, Director of Standards
Development

New Standard

Primary Contact
Scott Barfield-McGinnis, Standards Developer

Revision to existing Standard

Telephone
Fax

404-446-9689

Withdrawal of existing Standard

E-mail

[email protected]

Urgent Action

Purpose
Prevent a potential compliance overlap with the current Reliability Standard PRC-023-2 –
Transmission Relay Loadability, which became effective July 1, 2012. The overlap would be created
when the proposed PRC-025-1 – Generator Relay Loadability, which is currently under development,
is approved and becomes effective.
Industry Need
The generator relay loadability standard drafting team identified conditions in the development of
the drafting of the PRC-025-1 standard that would create the potential for overlap (e.g., “double
jeopardy”) and confusion as to which standard is applicable to the Generator Owner entity (i.e., PRC023-2 or PRC-025-1).
Brief Description
This request includes modifying PRC-023-2 to add clarity to the Applicability section of the PRC-023-2
standard. Other modifications include updating references from the version number to reflect the
new version number. Detail regarding the effective dates may be removed as the new version is
anticipated to become approved beyond the implementation plan for the current version.
Detailed Description
The generator relay loadability standard drafting team (GENRLOSDT) continues to evaluate the best
alternative to modifying PRC-023-2 to clarify the Generator Owner’s applicability with regard to loadresponsive protective relays. The drafting team has provided a redline draft to PRC-023-2 with a
proposed solution to the issue; however, the drafting team recognizes that the draft PRC-025-1 may
provide the opportunity to remove the Generator Owner from PRC-023-2 and therefore eliminate
the overlap and confusion without creating a gap in reliability.
The drafting team considered whether changes would be necessary to Requirement R1, criterion 6
and decided it should remain in the standard as there may be cases where PRC-023 will be applicable
to lines that connect generation stations remote to load. The drafting team has not revealed any
concerns about this criterion in relation to the proposed PRC-025-1 standard currently being drafted.
The effective date of the draft PRC-023-3 is anticipated to occur beyond the Implementation Plan
approved in version two; therefore, the effective date tables are proposed for removal. If an interim
implementation is required to bridge PRC-023-2 to the next version, the standard drafting team will
modify the effective date tables accordingly.
A complete review of the standard will be conducted to reveal any editorial edits that may be
needed to improve the quality of the Reliability Standard.
Industry commenting, balloting, and approval of the revisions to the draft PRC-023-3 standard will
occur contemporaneously with the drafting of the proposed PRC-025-1 standard. Adoption of PRC023-3 will contingent upon PRC-025-1.

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1)
Supplemental Standard Authorization Request (Revision to PRC-023-2)

2

Reliability Functions

The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Responsible for the real-time operating reliability of its Reliability
Coordinator
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Integrates resource plans ahead of time, and maintains loadAuthority
interchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange
Ensures communication of interchange transactions for reliability
Authority
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning
Assesses the longer-term reliability of its Planning Coordinator Area.
Coordinator
Resource
Develops a >one year plan for the resource adequacy of its specific
Planner
loads within its portion of the Planning Coordinator’s Area.
Transmission
Owns and maintains transmission facilities.
Owner
Transmission
Ensures the real-time operating reliability of the transmission assets
Operator
within a Transmission Operator Area.
Transmission
Develops a >one year plan for the reliability of the interconnected
Planner
Bulk Electric System within the Transmission Planner Area.
Transmission
Administers the transmission tariff and provides transmission
Service Provider services under applicable transmission service agreements (e.g., the
pro forma tariff).
Distribution
Delivers electrical energy to the End-use customer.
Provider
Generator
Owns and maintains generation facilities.
Owner
Generator
Operates generation unit(s) to provide real and reactive power.
Operator
PurchasingPurchases or sells energy, capacity, and necessary reliability-related
Selling Entity
services as required.
Load-Serving
Secures energy and transmission service (and reliability-related
Entity
services) to serve the End-use Customer.

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1)
Supplemental Standard Authorization Request (Revision to PRC-023-2)

3

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 nonsensitive information that is required for compliance with reliability standards. Yes

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1)
Supplemental Standard Authorization Request (Revision to PRC-023-2)

4

Related Standards

Standard No.

Explanation

None.

Related SARs

SAR ID

Explanation

Regional Variances

Region

Explanation

ERCOT

None.

FRCC

None.

MRO

None.

NPCC

None.

RFC

None.

SERC

None.

SPP

None.

WECC

None.

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1)
Supplemental Standard Authorization Request (Revision to PRC-023-2)

5

Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinator
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 below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES
5. Effective Dates
First day of the first calendar quarter beyond the date that this standard is approved by applicable
regulatory authorities, or in those jurisdictions where regulatory approval is not required, the

1 of 14

Standard PRC-023-3 — Transmission Relay Loadability
standard becomes effective on the first day of the first calendar quarter beyond the date this
standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
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 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, 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.

1

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.

2 of 14

Standard PRC-023-3 — 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 capability2.
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 temperature3.
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.
2

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
3

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.

3 of 14

Standard PRC-023-3 — Transmission Relay Loadability
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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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)
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)

4 of 14

Standard PRC-023-3 — Transmission Relay Loadability
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 PRC-023-3, 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.
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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

5 of 14

Standard PRC-023-3 — Transmission Relay Loadability
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 Enforcement Authority 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.

6 of 14

Standard PRC-023-3 — Transmission Relay Loadability

2.

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.

R2

R3

N/A

N/A

N/A

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

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.

7 of 14

Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

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.

8 of 14

Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

High
months or more 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 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)

Severe
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

9 of 14

Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

10 of 14

Standard PRC-023-3 — 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

1

February 12, 2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for approval
April 19, 2010

Changed VRF for R3 from Medium to High;
changed VSLs for R1, R2, R3 to binary Severe
to comply with Order 733

Revision

2

March 10, 2011
approved by Board
of Trustees

Revised to address initial set of directives from
Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with PRC025-1 and other minor corrections

Supplemental SAR
(Project 2010-13.2)

Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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.

Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 analyses4 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.

4

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

Standard PRC-023-3 — 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.

Standard PRC-023-23 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-23

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-023-23 - Attachment A, applied toat the terminals of the 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 toat the terminals of the 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-023-23 - Attachment A, applied toat the terminals of the circuits defined in
4.2.1 (Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional 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 below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES

1 of 18

Standard PRC-023-23 — 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:

2 of 18

Standard PRC-023-23 — Transmission Relay Loadability
Effective Date
Requirement

R1

Applicability

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where
No Regulatory
Approval is Required

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

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

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 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
(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, 20111

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

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

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.

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Standard PRC-023-23 — Transmission Relay Loadability
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
Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement R6

R2 and R3

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where
No Regulatory
Approval is Required

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

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

First day of the first
calendar quarter after
applicable regulatory
approvals

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

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

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

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Standard PRC-023-23 — Transmission Relay Loadability
Effective Date
Applicability

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where
No Regulatory
Approval is Required

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

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

R5

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

R6

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

Requirement

5 of 18

Standard PRC-023-23 — Transmission Relay Loadability
First day of the first calendar quarter beyond the date that this standard is approved by applicable
regulatory authorities, or in those jurisdictions where regulatory approval is not required, the
standard becomes effective on the first day of the first calendar quarter beyond the date this
standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
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 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.

2

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.

6 of 18

Standard PRC-023-23 — Transmission Relay Loadability
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 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 temperature4.
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.

3

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.

7 of 18

Standard PRC-023-23 — 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 PRC-023-3, 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-023-23 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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)

8 of 18

Standard PRC-023-23 — 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 PRC-023-3, 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.
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.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

9 of 18

Standard PRC-023-23 — Transmission Relay Loadability
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 MonitorEnforcement Authority 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.

10 of 18

Standard PRC-023-23 — Transmission Relay Loadability

2.

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.

R2

R3

N/A

N/A

N/A

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

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.

11 of 18

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

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.

12 of 18

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

High
months or more 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 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)

Severe
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

13 of 18

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

14 of 18

Standard PRC-023-23 — 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

1

February 12, 2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for approval
April 19, 2010

Changed VRF for R3 from Medium to High;
changed VSLs for R1, R2, R3 to binary Severe
to comply with Order 733

Revision

2

March 10, 2011
approved by Board
of Trustees

Revised to address initial set of directives from
Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with PRC025-1 and other minor corrections

Supplemental SAR
(Project 2010-13.2)

Standard PRC-023-23 — Transmission Relay Loadability
PRC-023-3 — 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.

Standard PRC-023-23 — Transmission Relay Loadability
PRC-023-3 — 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 analyses5 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.

5

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

Standard PRC-023-23 — 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.

Implementation Plan

Project 2010-13.2 - Relay Loadability: Generator
Requested Approvals

PRC-023-3 – Transmission Relay Loadability
Requested Retirements

PRC-023-2 – Transmission Relay Loadability
Prerequisite Approvals

PRC-025-1 – Generator Relay Loadability
A supplemental SAR was approved by the Standards Committee at their January 16-17, 2013 meeting
to authorize the drafting team to make changes to PRC-023-2 to comport with the proposed draft PRC025-1 – Generator Relay Loadability and in order to establish a bright line between the applicability of
load-responsive protective relays in the current transmission and the proposed generator relay
loadability standards.
Revisions to Defined Terms in the NERC Glossary

None
Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern about the
potential for overlap between existing PRC-023-2 – Transmission Relay Loadability standard, effective in the
United States on July 1, 2012, and the proposed PRC-025-1 – Generator Relay Loadability standards. The
concern is that there was no bright line to clearly distinguish which load-responsive protective relays pertain
to each standard. The drafting team researched the issue and proposed to modify the applicability section of
PRC-023-2 to clarify the each functional entity’s applicability with respect to which terminal the loadresponsive protective relay is connected to within the Transmission system.
General Considerations

The Implementation Plan period reflects consideration that a specific period is not required because no new
entity or facilities are subject to compliance. Also, it is expected that implementation plan and period for PRC023-2 will have been achieved and that it will not need to be considered in conjunction with this revision.
Applicable Entities

Distribution Provider

Generator Owner
Planning Coordinator
Transmission Owner
Effective Date
New Standard

PRC-023-3

First day of the first calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the
first day of the first calendar quarter beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.

Standards for Retirement

PRC-023-2

Midnight of the day immediately prior to the Effective Date of PRC-023-2 –
Transmission Relay Loadability in the particular jurisdiction in which the new
standard is becoming effective.

Implementation Plan for Definitions

No definitions are proposed as a part of this standard.
Implementation Plan for PRC-023-3, All requirements

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to
this standard shall be 100% compliant on the effective date of the standard according to the jurisdiction.

Implementation Plan (PRC-023-3)
Project 2010-13.2 - Relay Loadability: Generator (SAR Draft 1: January 17, 2013)

2

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
PRC-023-2
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

Proposed Replacement Requirement(s)
PRC-023-3
4.1.Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection
systems as described in PRC-023-2 3 - Attachment A, applied at the
terminals of the 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 at the
terminals of the 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 3 - Attachment A, applied at the
terminals of the 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

Notes: The change in applicability creates a bright line between those load-responsive protective relays that are applicable to PRC-023-3 –
Transmission Relay Loadability and the proposed PRC-025-1 – Generator Relay Loadability. This is evident by the minor changes to the
applicability text to distinguish the applicability of the relays by which “terminal” the load-responsive protective relay is connected to within the
Transmission system.

Implementation Plan (PRC-023-3)
Project 2010-13.2 - Relay Loadability: Generator (SAR Draft 1: January 17, 2013)

3

Unofficial Comment Form

Project 2010-13.2 – Phase II Relay Loadability: Generator
SAR for PRC-023-3
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard Authorization Request (SAR). Comments must be submitted by 8 p.m. ET
Monday, March 11, 2013. If you have questions please contact Scott Barfield-McGinnis at
[email protected] or by telephone at (404) 446-9689.
http://www.nerc.com/filez/standards/Project_2010-13.2_Summary_Table.html
Background Information

This posting is soliciting informal comment.
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) continues to evaluate the best
alternative to modifying PRC-023-2 to clarify the Generator Owner’s applicability with regard to loadresponsive protective relays. The drafting team has provided a redline draft to PRC-023-2 with a proposed
solution to the issue.
The drafting team considered whether changes would be necessary to Requirement R1, criterion 6 and
decided it should remain in the standard as there may be cases where PRC-023 will be applicable to lines
that connect generation stations remote to load. The drafting team has not revealed any concerns about
this criterion in relation to the proposed PRC-025-1 standard currently being drafted.
The effective date of the draft PRC-023-3 is anticipated to occur beyond the Implementation Plan
approved in version two; therefore, the effective date tables are proposed for removal. If an interim
implementation is required to bridge PRC-023-2 to the next version, the standard drafting team will
modify the effective date tables accordingly.
A complete review of the standard will be conducted to reveal any editorial edits that may be needed to
improve the quality of the Reliability Standard.
Industry commenting, balloting, and approval of the revisions to the draft PRC-023-3 standard will occur
contemporaneously with the drafting of the proposed PRC-025-1 standard. Adoption of PRC-023-3 will
contingent upon PRC-025-1.
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.

Questions

The scope of this project includes:

•

Adding to each functional entity description, the phrase “at the terminals of the” to specify where
the load-responsive protective relay is located

•

Update the standard version numbers

•

Include any editorial edits or updates to current standard text

1. Do you agree with this scope? If not, please explain.
Yes
No
Comments:
2. The SAR identifies a list of reliability functions that may be assigned responsibility for requirements
in the set of standards addressed by this SAR. Do you agree with the list of proposed applicable
functional entities? If no, please explain.
Yes
No
Comments:
3. Do the proposed changes in the draft PRC-023-3 – Transmission Relay Loadability create the
necessary bright line between the draft PRC-025-1 – Generator Relay Loadability create the bright
line between the two standards? If no, please explain what would make the bright line clearer.
Yes
No
Comments:
4. Are you aware of any regional variances that will be needed as a result of this project? If yes,
please identify the regional variance.
Yes
No
Comments:

Unofficial Comment Form (SAR PRC-023-3)
Project 2013-13.2 GENRLO

2

5. Are you aware of any business practice that will be needed or that will need to be modified as a
result of this project? If yes, please identify the business practice.
Yes
No
Comments:
6. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form (SAR PRC-023-3)
Project 2013-13.2 GENRLO

3

Standards Announcement
Project 2010-13.2 – Phase 2 of Relay Loadability: Generation
Ballot Pools Forming: January 25 – February 25, 2013
Formal Comment Period: January 25 – March 11, 2013
Additional Documents Posted for Comment:
Cost Effectiveness Comment Period: January 25 – March 11, 2013
Supplemental SAR Informal Comment Period: January 25 – March 11, 2013
RSAW Posted for Industry Comments: January 25 – March 11, 2013
Upcoming:
Initial Ballot and Non-Binding Poll: March 1 – March 11, 2013
Now Available

A formal comment period for PRC-025-1 – Generator Relay Loadability is open through 8 p.m. Eastern
on Monday, March 11, 2013 and ballot pools are forming through 8 a.m. Monday, February 25, 2013
(please note that ballot pools close at 8 a.m. Eastern and mark your calendar accordingly).
An initial ballot of PRC-025-1 and non-binding poll of the associated VRFs and VSLs will also be
conducted during this period, beginning on Friday, March 1, 2013 through 8 p.m. Eastern on Monday,
March 11, 2013.
Alongside the comment period, three additional documents will be posted for industry comment: a
draft cost effective analysis (CEA), a supplemental SAR, and a draft Reliability Standard Audit
Worksheet (RSAW).
In response to concerns expressed by stakeholders and regulators, NERC has developed a Cost
Effective Analysis Process (CEAP) to introduce the concept of cost consideration and effectiveness into
the development of new and revised standards. As part of the pilot of the CEAP, NERC is proposing to
conduct a CEA to provide information about cost impacts of draft Reliability Standards and their
relative effectiveness, which will allow the industry to evaluate and propose alternative approaches for
achieving the reliability objectives of the standard. The revisions under Project 2010-13.2 have been
deemed to be required to meet an adequate level of reliability, and therefore, “Phase I” of the CEAP (a
cost impact assessment) is unnecessary. A pilot of “Phase II” of the CEAP, the CEA, is posted for
industry comment through 8 p.m. Eastern on Monday, March 11, 2013. More information about the
CEAP is available on the project page.

A supplemental SAR has also been developed to revise PRC-023-2 and is posted for an informal
comment period.
Finally, PRC-025-1 was drafted in conjunction with the development of its RSAW, which is posted for an
informal comment period.
Instructions for Joining Ballot Pool(s)

Ballots pools are being formed for the standard and non-binding poll for PRC-025-1. Registered Ballot
Body members must join both ballot pools to be eligible to vote in the balloting of PRC-025-1 and to
submit an opinion for the non-binding poll of the associated VRFs and VSLs. Registered Ballot Body
members may join the ballot pools at the following page: Join Ballot Pool.
During the pre-ballot window, members of the ballot pool may communicate with one another by
using the “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from
using the ballot pool list server.) The ballot pool list servers for the ballot pools are:
Initial ballot: [email protected]
Non-binding poll: [email protected]
Instructions for Commenting

A formal comment period is open for PRC-025-1 through 8 p.m. Eastern on Monday, March 11, 2013.
The supplemental SAR to revise PRC-023-2 and CEA have also been posted for industry comment.
Please use the links below to the electronic comment forms to submit comments:
PRC-025-1
Supplemental SAR
Cost Effective Analysis
If you experience any difficulties in using the electronic form, please contact Wendy Muller at
[email protected]. An off-line, unofficial copy of the comment form is posted on the project
page.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Monday, March 11, 2013.
The draft RSAW is posted on the NERC Compliance Reliability Standard Audit Worksheet page. Please
submit comments on the draft RSAW by using the RSAW feedback form on the project page and
sending to: [email protected].
Next Steps

An initial ballot will be conducted March 1, 2013 through 8 p.m. Monday, March 11, 2013.
Background

The March 18, 2010 FERC Order No. 733 approved Reliability Standard PRC-023-1 – Transmission Relay
Loadability. In this Order, FERC directed NERC to address three areas of relay loadability that include
modifications to the approved PRC-023-1, developing a new Reliability Standard to address generator

Standards Announcement
Project 2010-13.2 GENRLO

2

protective relay loadability, and developing another Reliability Standard to address the operation of
protective relays due to power swings. This project’s SAR addresses these directives and establishes a
three-phase approach to standard development.
Phase I was focused on making the specific modifications to PRC-023-1 and was completed in the
approved PRC-023-2 Reliability Standard, which became mandatory on July 1, 2012. This project, Phase
II, is focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay Loadability, to
address generator protective relay loadability. This Reliability Standard establishes requirements for
the Generator Operator functional entity to set protective relays at a level such that generating units
do not trip during system disturbances that are not damaging to the generator thereby unnecessarily
removing the generator from service. Phase III, which will follow this project, will focus on developing
requirements that address protective relay operations due to stable power swings.
Additional information can be found on the project page.
Standards Development Process

The Standards 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

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

Standards Announcement
Project 2010-13.2 GENRLO

3

Name (9 Responses)
Organization (9 Responses)
Group Name (11 Responses)
Lead Contact (11 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (0 Responses)
Comments (20 Responses)
Question 1 (19 Responses)
Question 1 Comments (20 Responses)
Question 2 (19 Responses)
Question 2 Comments (20 Responses)
Question 3 (19 Responses)
Question 3 Comments (20 Responses)
Question 4 (19 Responses)
Question 4 Comments (20 Responses)
Question 5 (19 Responses)
Question 5 Comments (20 Responses)
Question 6 (0 Responses)
Question 6 Comments (20 Responses)

Group
Tennessee Valley Authority
Brandy Spraker
Yes
Yes
No
Though the line could be derived from reading the purpose of the standard, it may help avoid
potential confusion to the generator owners by specifically excluding generator step-up units from
4.2.1.6 or the second bullet of Attachment B.
No
No

Group
Northeast Power Coordinating Council
Guy Zito
No
The Industry Need statement, as written, implies that the burden of the overlap between PRC-023-3
and PRC-025-1rests with the Generator Owner as the owner of the protection for the elements that
connect the generator to the transmission system. The intent of the drafting teams for PRC-023-3 and
PRC-025-1 is to segregate the standards so that load-responsive relays used for generator protection
are in one standard (PRC-025-1) and load-responsive relays used to protect transmission are in
another (PRC-023-3). The Applicability section of PRC 025-1 refers to generator interconnected
Facilities which can be construed to mean Generator Owners are responsible for this protection and
the terminals at each end. There are Transmission Owners that own protection assets on some, if not
all of the terminals for a generator’s interconnection. Terminal responsibility needs clarification. The
wording places emphasis on asset ownership.
No

The Reliability Functions table has the Planning Coordinator checked. The Planning Coordinator by
definition in the NERC Functional Model is “The functional entity that coordinates, facilitates,
integrates and evaluates (generally one year and beyond) transmission facility and service plans, and
resource plans within a Planning Coordinator area and coordinates those plans with adjoining Planning
Coordinator areas.” The Planning coordinator does not get involved with generator and transmission
relay loadability.
No
The draft SAR and proposed standards PRC-023-3, PRC-025-1 fail to provide a clear distinction as to
whether the standard is meant to apply to the owner of a protection system designed to protect
transmission elements (which we believe is the intent of PRC-023-3), or the owner of a protection
system designed to protect generation elements (which we believe is the intent of PRC-025-1). We
believe this was the intent, but the applicability section of either of the proposed standards does not
clearly articulate that intent. Suggest the SDT consider an approach similar to that used in PRC-006-1
where the SDT chose to create a ‘standard specific entity’; UFLS entities. Alternatively, the
applicability could be modified to more closely match the intent indicated in the Applicability section of
the Guideline and Technical Basis document, and in the wording of the Supplemental SAR for Project
2010-13.2 Relay Loadability Order 733 Phase 2 (Relay Loadability: Generation). The standard should
be applied to the owner of the particular type of protection system, not applied to a particular
function. We are aware of circumstances whereby an entity registered as Transmission Owner owns
the protection system that protects for faults on the element(s) owned by an entity registered as a
Generator Owner which are solely used to interconnect their generator to the bulk power system. We
are also aware of circumstances whereby the Generator Owner owns both the element(s) which are
solely used to interconnect their generator to the bulk power system as well as the protection system
that protects for faults on those generator interconnection element(s). In both of these, the
protection system is designed to protect the bulk power system from the fault, not the generator
itself. Changes to proposed PRC 023-2 and PRC 025-1 attempt to establish a bright line, but the
functional entity of Generator Owners is still included in PRC 023-3. This results in confusion as to
what standard applies for the elements that connect the generator to the BES, as some Transmission
Owners own GSU assets. The wording of PRC-025-1, and as stated in the Webinar, imply that “leads
assets” will fall under PRC-025-1. There is still confusion in this area so a bright line still has not been
established.
No
No
It needs to be made clear that owning the protection systems at the terminals does not imply
ownership of the facility. Entities may be responsible for protective relays on each end of a “lead”, but
the leads but may be in facilities where one end is owned by a Transmission Owner, and the other
end facility is owned by a Generator Owner. The removal of the “Effective Dates” table needs to be
re-examined. Among other things, this table included the timelines for meeting PRC-023 on sub200kV Facilities. If a sub-200kV Facility is identified by the Planning Coordinator, pursuant to
Requirement R6, Transmission Owners, Generator Owners, and Distribution Providers must be given a
grace period in which to make protection modifications before PRC-023 is applicable to that Facility.
PRC-023-2 included a 39-month window for modifying these Facilities once they’ve been identified by
the Planning Coordinator. This is an oversight that will cause confusion. In PRC-023-3, in 4.1.2 PRC
023-2 needs to be changed to PRC-023-3.
Group
PacifiCorp
Ryan Millard
Yes
Yes
Yes

No
No
Section 4.1 states that the Transmission Owner, Generator Owner, and Distribution Provider with
load-responsive phase protection systems at the terminal of the circuits is responsible for ensuring
compliance with PRC-023-3. PacifiCorp maintains that more clarification is needed with respect to who
is ultimately responsible for ensuring compliance in instances where the circuit/transmission line has a
different owner. Would the owner of the circuit/transmission line rely on the owner of the relays for
ensuring compliance?
Group
Luminant
Brenda Hampton
Yes
Yes
Yes
No
No

Group
Southwest Power Pool Standards Development Team
Jonathan Hayes
Yes
Yes
No
While we agree that the revision to PRC023-2 creates a bright line we feel that language should be
included in PRC-25-1 to clearly state that the protection relays under PRC023-2 ,or -3 if the SAR is
approved, would be not be applicable under PRC025-1.
No
No

Group
ACES Standards Collaborators
Ben Engelby
No
(1) In order to have a clear “bright line,” the generator owner should not apply to PRC-023. Remove
all reference to GO from PRC-023, and then the SAR will satisfy the intent of avoiding double

jeopardy.
No
(1) The purpose of the revised SAR is to remove the applicability of GOs for PRC-023-2. Therefore, we
recommend unselecting the Generator Owner box in the supplemental SAR, as the revised standard
would not apply to GOs.
No
See comments above. There should not be any references to generators in the transmission
loadability standard.
No
No
(1) We disagree with including GOs as an applicable entity to PRC-023-2. In order to create a “bright
line,” the drafting teams should have separate standards. Have PRC-023 apply to transmission and
have PRC-025 apply to generators. It is a simple dividing line. If the team feels that any of the
loadability criteria from the transmission loadability standard should be included in PRC-025, then do
so, but do not leave any reference to GOs in PRC-023. (2) With the proposed PRC-023-3, there is
overlap for GOs. The GO is listed in all six requirements in PRC-023 and in R1 of PRC-025. We
recommend removing all references to GOs in PRC-023. If this cannot be accomplished, then update
PRC-023-3 to include the aspects of PRC-025 and stop developing a duplicative standard.
Group
Salt River Project
Bob Steiger
Yes
Yes
Yes
No
No
No Comment
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
Yes
Yes
Yes
No
Yes
Elimination of the table under number 5 of section A in PRC-023-2.
Comments to NERC on Proposed PRC-023-3 Standard It is understood that PRC-023-3 is intended to

replace PRC-023-1 and PRC-023-2 in the near future. The changes proposed for PRC-023-3 in
comparison with PRC-023-2 are mainly the removal of the table under number 5 of section A. The
table being removed provides the effective dates of the requirements in the PRC-023-2 standard
corresponding to the applicable Functional Entities and circuits. Entergy has concerns over the
removal of the table as explained below. Our specific area of concern is on the effective date of PRC023-3 which is defined in the standard as the “first day of the first calendar quarter beyond the date
that this standard is approved by applicable regulatory authorities”. (See the bottom of page 1 of the
proposed PRC-023-3 standard.) In the Implementation Plan for the proposed PRC-023-3 standard, it
is stated that entities applicable to this standard shall be 100% compliant on the effective date of the
standard. (See the last line on page 2 of the Implementation Plan.) In other words, the
Implementation Plan considers a specific implementation period as not required based on the
following two reasons. (See section General Considerations at the bottom of page 1 of the
Implementation Plan.) 1. No new entity or facilities are subject to compliance. 2. The implementation
plan and period for PRC-023-2 will have been achieved. Entergy sees some scenarios that do not
agree with either or both of the above reasons. In such scenarios, the PRC-023-3 effective date and
Implementation Plan become problematic. In short, PRC-023-3 proposes to retroactively eliminate the
NERC-defined implementation time for ongoing PRC-023-2 compliance activities. A couple of scenarios
are provided below for illustration purposes. The first scenario is related to the effective date of
requirements R6 and R1 of PRC-023-2. PRC-023-2 became effective in the United States on July 1,
2012. (See the Background section on page 1 of the Implementation Plan for PRC-023-3.) However,
PRC-023-2 gives various effective dates that are to be phased in over the period of more than four
years. According to the table on pages 2-4 of the PRC-023-2 standard, R6 will become effective on
1/1/2014. For circuits identified by the Planning Coordinator pursuant to Requirement R6, R1 is to be
effective 39 months following notification by the Planning Coordinator of their inclusion on a list of
circuits subject to PRC-023-2 per application of Attachment B. It means that the applicable entity is
given 39 months to develop and implement a plan to bring the applicable circuits to compliance.
Therefore, the compliance date can be as late as 4/1/2017 or beyond depending on when the
Planning Coordinator will send out its notification on applicable circuits. If PRC-023-3 becomes
effective before such date, it will be problematic. For reference, the relevant effective dates for R6
and R1 as specified in PRC-023-2 (Please review Effective Dates as provided in table for NERC
Standard PRC-023-2). The second scenario is about new circuits identified by Planning Coordinator
during its assessments that are required to be conducted at least once each calendar year pursuant to
R6 of PRC-023-3. (See the middle of page 4 of the PRC-023-3 standard.) When new circuits are
identified as the result of the yearly assessment, applicable entities will need reasonable amount of
time to bring the circuit to compliance. This time period is necessary for budget reasons as well as
project planning and construction reasons. While both PRC-023-1 and PRC-023-2 recognize such a
need, the proposed standard PRC-023-3 does not. (See section 5.1.3 on page 1 of PRC-023-1 and
effective date table on pages 2-4 of PRC-023-2.) Entergy suggests that a 39 months long period of
time be given to applicable entities to comply with the PRC-023-3 standard for each facility that is
added to the Planning Coordinator’s list. Please review the referenced NERC standard documents. 1)
NERC Standard PRC-023-1 2) NERC Standard PRC-023-2 3) NERC Proposed Standard PRC-023-3
(clean) 4) NERC PRC-023-3 Implementation Plan
Individual
Thad Ness
American Electric Power
Yes
Yes
No
AEP believes that the proposed changes in the draft PRC-023-3 create a bright line identifying the
scope of PRC-023-3. However, the proposed draft of PRC-025-1 does not create a bright line
identifying the scope of PRC-025-1. Load-responsive protective relays installed on the high side
terminals of the Generator Step-Up transformer looking towards the Transmission system are clearly
in scope for PRC-023-3 but are not clearly excluded from being applicable from PRC-025-1. AEP

recommends including in PRC-025-1 verbiage clearly excluding load-responsive protective relays
applicable to PRC-023-3 from PRC-025-1.
No
No
AEP believes there is a typo in PRC-023-3 Section 4.1.2. The statement references PRC-023-2 instead
of the current standard revision.
Individual
Ed Croft
Puget Sound Energy
Yes
No
Possibly the GO (section 4.1.2) should be taken out. This function is covered in PRC-025. Taking the
GO function out of PRC-023 (and any accompanying items) would further strengthen the brightline
between PRC-023-3 and PRC-025-1.
No
see answer to question 2
No
No

Individual
Nazra Gladu
Manitoba Hydro
No
(1) Similar to PRC-025, the phrase “while maintaining reliable protection of the BES” is vague. There
are no objective criteria specified for this determination, nor is it clear whether this element will be
audited in some fashion. If this element of the requirement cannot be audited, it should be deleted.
At a minimum, it should specify that the Responsible Entity makes this determination in its sole
discretion.
Yes
No comment.
No
(1) In section 4.1.1, 4.1.2 and 4.1.3, the redlined part “at the terminals of” should be changed to “at
the Transmission Owner terminals of”, “at the generator owner terminals of” and “at the Distribution
Owner terminals of”. Also, PRC-023-2 in section 4.1.2 should be changed to PRC-023-3.
No
No comment.
No
No comment.
No comment.
Individual
Michael Falvo
Independent Electricity System Operator

Yes
Yes
Yes
No
No

Group
Dominion
Mike Garton
No
Dominion believes the Industry Need as indicated in the SAR could be better stated. We believe the
intent of the drafting teams for PRC-023 and PRC-025 is to segregate the standards so that loadresponsive relays used for generator protection are in one standard (PRC-025) and load-responsive
relays used to protect the bulk power system (Transmission as defined in the NERC Glossary ; An
interconnected group of lines and associated equipment for the movement or transfer of electric
energy between points of supply and points at which it is transformed for delivery to customers or is
delivered to other electric systems.) are in another (PRC-023). The SAR as written appears to infer
that, in all cases, the GO owns the protection system that contains the load-responsive relays that
protect Transmission (as defined in the NERC Glossary) from faults that occur on the element(s) that
make up the Facility used to connect the generator to Transmission. PRC 025 refers to generator
interconnected Facilities (ie generator leads..some refer to this as GSU leads) which implies Generator
Owners are responsible for this protection and the terminals at each end. There are TOs that own
“lead” assets either on both ends or possibly one end of the leads. This is an area that needs further
clarification when referring to terminal responsibility. Appears now that wording places emphasis on
asset ownership?
No
Under 4.1.2 PRC 023-2 needs to be changed to PRC023-3.
No
The draft SAR and proposed standards PRC-023-3, PRC-025-1 fail to provide a clear distinction as to
whether the standard is meant to apply to the owner of a protection system designed to protect
transmission elements (which we believe is the intent of PRC-023) or the owner of a protection
system designed to protect generation elements (which we believe is the intent of PRC-025). We
believe this was the intent of the SDT but we don’t believe the applicability section of either of the
proposed standards clearly articulates that intent. We suggest the SDT consider an approach similar
to that used in PRC-006-1 where the SDT chose to create a ‘standard specific entity’; UFLS entities.
Alternatively, the applicability could be modified to more closely match the intent as indicated in the
Applicability section of the Guideline and Technical Basis document and the Supplemental SAR for
Project 2010-13.2 Relay Loadability Order 733 Phase 2 (Relay Loadability: Generation). We believe
the standard should be applied to the owner of the particular type of protection system, not applied to
a particular function. We are aware of circumstances whereby an entity registered as TO owns the
protection system that protects for faults on the element(s) owned by an entity registered as a GO
which are solely used to interconnect their generator to the bulk power system. We are also aware of
circumstances whereby the GO owns both the element(s) which are solely used to interconnect their
generator to the bulk power system as well as the protection system that protects for faults on those
generator interconnection element(s). In both of these, the protection system is designed to protect
the bulk power system from the fault, not the generator itself. Changes to proposed PRC 023-2 and
PRC 025-1 attempts to establish a bright line but the functional entity of Generator Owners is still
included in PRC 023 so this results in confusion as to what standard applies for the elements that

connect the generator to the BES as some Transmission Owners own GSU assets but the new
standard and as stated on the Webinar it implies that “leads assets” will fall under PRC 025. There is
still confusion in this area so a bright line still has not been established.
No
No
It needs to be clear that at the terminals does not imply ownership. Entities may be responsible for
protective relays on each end of the leads but may be in facilities where one end is owned by a TO
and the other end facility is owned by a GO. - The removal of the “Effective Dates” table needs to be
reexamined. Among other things, this table included the timelines for meeting PRC-023 on sub-200kV
Facilities. If a sub-200kV Facility is identified by the Planning Coordinator, pursuant to Requirement
R6, Transmission Owners, Generator Owners, and Distribution Providers must be given a grace period
in which to make protection modifications before PRC-023 is applicable to that Facility. PRC-023-2
included a 39-month window for modifying these Facilities once they’ve been identified by the
Planning Coordinator. This is an oversight that will cause confusion.
Individual
Timothy Brown
Idaho Power Co.
Yes
Yes
Yes
No
No
There will obviously be additional work to perform the analysis needed to be compliant with the
standard. The only business practice that will need to be modified is to perform this analysis for any
new or modified generators or generator protective relays to ensure compliance.
Individual
Dale Fredrickson
Wisconsin Electric Power Company
No
Adding this phrase does little to remove the confusion as to applicability to Generator Owners.
No
The applicability of this standard should be removed from the Generator Owner.
No
Any requirements applicable to the Generator Owner should be in a single standard, PRC-025-1.
When this standard is approved, Generator Owners that employ load-sensitive relaying on the highvoltage side of the generator step-up transformer, between the GSU and the interconnection with the
Transmission system, will be subject to the PRC-025-1 requirements in 3.2.4 for Generator
interconnection Facilities, and at that time the PRC-023 standard should have all applicability to
Generator Owners removed.
No
No

Individual
Travis Metcalfe
Tacoma Power
No
The phrase “at the terminals of the” does not seem to mitigate the potential overlap between PRC023 and PRC-025. Should not the distinction be drawn for generation interconnection Facility(ies)? In
other words, it seems that transmission lines only connecting generation would be subject to PRC025-1 and that transmission lines that are part of the more interconnected transmission system would
be subject to PRC-023-3. If the Generator Relay Loadability Standard Drafting Team disagrees,
additional clarification is requested as to how the phrase “at the terminals of the” mitigates the
potential overlap.
Yes
No
The phrase “at the terminals of the” does not seem to mitigate the potential overlap between PRC023 and PRC-025. Should not the distinction be drawn for generation interconnection Facility(ies)? In
other words, it seems that transmission lines only connecting generation would be subject to PRC025-1 and that transmission lines that are part of the more interconnected transmission system would
be subject to PRC-023-3. If the Generator Relay Loadability Standard Drafting Team disagrees,
additional clarification is requested as to how the phrase “at the terminals of the” mitigates the
potential overlap.
No
No

Group
PPL Corporation NERC Registered Affiliates
Stephen J. Berger
No
The PPL Companies do not agree that addition of the phrase includes the specificity needed to ensure
“double jeapordy” for generation. As stated by the North American Generators Forum standards
review team: Load-responsive protective relays installed on the high side terminals of the Generator
Step-up transformer looking towards the Transmission system appear to be clearly in scope for PRC23-3 but are not clearly excluded from being applicable to PRC-025-1.
Yes
No
No
No

Individual
Bradley Collard
Oncor Electric Delivery LLC

Oncor is not registered as a Generator Owner, nor does it perform the functions of a Generator
Owner. Thus, this question is not applicable to Oncor.
Oncor is not registered as a Generator Owner, nor does it perform the functions of a Generator
Owner. Thus, this question is not applicable to Oncor.
Oncor is not registered as a Generator Owner, nor does it perform the functions of a Generator
Owner. Thus, this question is not applicable to Oncor.
Oncor is not registered as a Generator Owner, nor does it perform the functions of a Generator
Owner. Thus, this question is not applicable to Oncor.
No Comment
The phase-in time for a newly declared critical circuit was removed from the draft PRC-023-3 Effective
Dates section; the phase-in time needs to be added back to PRC-023-3. As written in PRC-023-2, R6
requires Planning Coordinators to conduct an assessment of critical circuits on a periodic basis and
provide “new circuits” to the appropriate registered entity. The Effective Dates section of PRC-023-2
states a registered entity will have 39 months to comply for newly declared critical circuits following
declaration by the Planning Coordinator. This phase-in time period provides necessary time for a
registered entity to budget and implement a project to meet PRC-023-2 compliance. The 39 month
phase-in period was an acceptable and approved timeframe and should be added back to PRC-023-3.
Group
SERC Protection and Controls Subcommittee
David Greene
Yes
Yes
Yes
No
No
There may be owner issues that impact entity registration.
- It needs to be clear that 'at the terminals' does not imply ownership. Entities may be responsible for
protective relays on each end of the leads but may be in facilities where one end is owned by a TO
and the other end facility is owned by a GO. - The removal of the “Effective Dates” table needs to be
reexamined. Among other things, this table included the timelines for meeting PRC-023 on sub-200kV
Facilities. If a sub-200kV Facility is identified by the Planning Coordinator, pursuant to Requirement
R6, Transmission Owners, Generator Owners, and Distribution Providers must be given a grace period
in which to make protection modifications before PRC-023 is applicable to that Facility. PRC-023-2
included a 39-month window for modifying these Facilities once they’ve been identified by the
Planning Coordinator. This is an oversight that will cause confusion. The comments expressed
herein(Questions 1-6) represent a consensus of the views of the above-named members of the SERC
EC Protection and Control Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.
Group
Bonneville Power Administration
Jamison Dye
No
The difference between “applied to circuits defined in 4.2.1” and “applied at the terminals of the
circuits defined in 4.2.1” is not clear. If there is any difference, it is subtle, and probably not worth
revising PRC-023-2 for. The bigger problem is that transmission lines over 200kV that attach

generating facilities to the BES seem to be covered by both PRC-023 and PRC-025. PRC-025 applies
to Generation interconnection Facilities, but there is no definition of this term. It seems that a 230kV
line that connects a GSU transformer to a substation would be considered to be a Generation
interconnection facility, and subject to both standards. Therefore, there are two very different
requirements that apply to the relays on such a line. A definition of Generator interconnection
Facilities is needed, and clarification of which standard the example given above would be covered by
is needed.
No
BPA believes there needs to be a clearer delineation between generator facilities and transmission
facilities and PRC-023 and PRC-025 written so that there is no overlap between the two. Then the
applicability of both PRC-023 and PRC-025 can be easily applied to the owners of the facilities covered
by that standard, whether they are registered as a GO, TO, or DP. As PRC-025 is proposed, it only
applies to GO’s, but what if a TO owns the relays applied to a GSU transformer? These relays would
presently not be covered by either PRC-023 or PRC-025.
No
As described in comments 1 and 2, BPA believes there needs to be a definition of “Generator
interconnection Facilities” if this term will be used in PRC-025. There needs to be a clear separation
between facilities included in PRC-023 and those included in PRC-025, with no overlap. The most
likely place for this separation would be at the high-voltage terminal of the GSU transformer, with the
GSU and everything between it and the generators included in PRC-025, and the line connecting the
GSU to the BES included in PRC-023.
No
No

Consideration of Comments

Project 2010-13.2 – Phase II Relay Loadability
SAR for PRC-023-3

The Project 2010‐13.2 Drafting Team thanks all commenters who submitted comments on the 
Standard Authorization Request (SAR) for PRC‐023‐3. The supplemental SAR was posted for a 45‐day 
public comment period from January 25, 2013 through March 11, 2013. Stakeholders were asked to 
provide feedback on the SAR and associated documents through a special electronic comment form.  
There were 20 sets of comments, including comments from approximately 89 different people from 
approximately 54 companies representing 9 of the 10 Industry Segments as shown in the table on the 
following pages. 

All comments submitted may be reviewed in their original format on the standard’s project page. 

If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give 
every comment serious consideration in this process!  If you feel there has been an error or omission, 
you can contact the Vice President and Director of Standards, Mark Lauby, at 404‐446‐2560 or at 
[email protected].  In addition, there is a NERC Reliability Standards Appeals Process.1 

Summary Consideration
There were no changes to the posted supplemental SAR in response to comments. Commenters were 
unclear about the division of responsibilities between the Generator Owner and Transmission Owner. 
Changes were made to both standards to address these concerns. Please refer to the summary changes 
to the proposed draft 2 of PRC‐023‐3 in the Consideration of Comments for draft 2 of PRC‐025‐1. 

1

 The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf 

Index to Questions, Comments, and Responses 
1. Do you agree with this scope? If not, please explain. ........................................................... 8 
2. The SAR identifies a list of reliability functions that may be assigned responsibility for
requirements in the set of standards addressed by this SAR. Do you agree with the list of
proposed applicable functional entities? If no, please explain............................................ 15 
3. Do the proposed changes in the draft PRC-023-3 – Transmission Relay Loadability create the
necessary bright line between the draft PRC-025-1 – Generator Relay Loadability create the
bright line between the two standards? If no, please explain what would make the bright line
clearer. .................................................................................................................... 19 
4. Are you aware of any regional variances that will be needed as a result of this project? If yes,
please identify the regional variance. ............................................................................ 28 
5. Are you aware of any business practice that will be needed or that will need to be modified as a
result of this project? If yes, please identify the business practice. .................................... 30 
6. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here: .................................................................................................... 33 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

2 

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

1.

Group 

Brandy Spraker 

Tennessee Valley Authority 

2

3

4

5

6

7

8

9

10

X 

X 

X 

X 

X 

Additional Member Additional Organization Region Segment Selection
1. Marjorie Parsons

SERC

6

2. Tom Vandervort

SERC

5

3. Annette Dudley

SERC

5

4. Paul Palmer

SERC

5

5. Lee Thomas

SERC

5

6. Daniel McNeely

SERC

1

7. Wayne Talley

SERC

1

2.

Group 

Guy Zito 

Additional Member

Northeast Power Coordinating Council 

Additional Organization

Region Segment Selection

1. Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2. Carmen Agavriloai

Independent Electricity System Operator

NPCC 2

Consideration of Comments: Project 2010‐13.2 
023‐3| April 24, 2013  

3 

Group/Individual 

Commenter 

Organization 

Registered Ballot Body Segment 
1

3. Greg Campoli

New York Independent System Operator

NPCC 2

4. Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

2

3

4

5

6

7

8

9

10

5. Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7. Mike Garton

Dominion Resources Services, Inc.

NPCC 5

8. Kathleen Goodman

ISO - New England

NPCC 2

9. Michael Jones

National Grid

NPCC 1

10. David Kiguel

Hydro One Networks Inc.

NPCC 1

11. Christina Koncz

PSEG Power LLC

NPCC 5

12. Randy MacDonald

New Brusnwick Power Transmission

NPCC 9

13. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

14. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

15. Robert Pellegrini

The United Illuminating Company

NPCC 1

16. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

17. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

18. Brian Robinson

Utility Services

NPCC 8

19. Brian Shanahan

National Grid

NPCC 1

20. Wayne Sipperly

New York Power Authority

NPCC 5

21. Bruce Metruck

New York Power Authority

NPCC 6

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

24. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

3.

Brenda Hampton 

Group 
Additional Member

1. Rick Terrill

Luminant 

Additional Organization

X 

X 

X 

X 

X 

X 

X 

Region Segment Selection

Luminant Generation Company LLC ERCOT 5

4.

Group 
Additional Member
1. Jonathan Hayes

Jonathan Hayes  

Southwest Power Pool Standards 
Development Team  

Additional Organization
Southwest Power Pool

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

Region Segment Selection
SPP

NA

4 

Group/Individual 

Commenter 

Organization 

Registered Ballot Body Segment 
1

2. Robert Rhodes

Southwest Power Pool

SPP

NA

3. John Allen

City Utilities of Springfield

SPP

1, 4

4. Chandler Brown

Sunflower Electric

SPP

1

5. Anthony Cassmeyer

Western Farmers Electric Cooperative SPP

1, 3, 5

6. Gary Condict

Sunflower Electric

SPP

1

7. Karl Diekevers

NPPD

MRO

1, 3, 5

8. Tiffany Lake

Westar Energy

SPP

1, 3, 5, 6

9. Valerie Pinamonti

AEP

SPP

1, 3, 5

10. Paul Reynolds

Sunflower Electric

SPP

1

11. Jerry White

Cleco

SPP

1, 3, 5

12. Don Schmit

NPPD

MRO

1, 3, 5

13. Paul Von Hersenberg Westar Energy

SPP

1, 3, 5, 6

14. Bo Jones

Westar Energy

SPP

1, 3, 5, 6

15. Lynn Schroeder

Westar Energy

SPP

1, 3, 5, 6

5.

Ben Engelby 

2

3

4

5

6

7

8

9

10

Group 
Additional Member

ACES Standards Collaborators 

Additional Organization

X 

X 

X 

X 

X 

X 

X 

X 

X 

Region Segment Selection

1. Megan Wagner

Sunflower Electric Power Corporation

SPP

1

2. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

3. Tom Alban

Buckeye Power, Inc.

RFC

3, 4

4. Mark Ringhausen

Old Dominion Electric Cooperative

SERC

3, 4

5. Chris Bradley

Big Rivers Electric Corporation

SERC

6. Bob Solomon

Hoosier Energy Rural Electric Cooperative, Inc. RFC

1

6.

Group 
Additional Member

Mike Garton 

Dominion 

Additional Organization

Region Segment Selection

1. Louis Slade

Dominion Resources Services, Inc.

RFC

5, 6

2. Randi Heise

Dominion Resources Services, Inc.

MRO

5, 6

3. Connie Lowe

Dominion Resources Services, Inc.

NPCC 5, 6

4. Michael Crowley

Virginia Electric and Power Company SERC

1, 3, 5, 6

7.

Group 

Stephen J. Berger 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

PPL Corporation NERC Registered Affiliates 

5 

Group/Individual 

Commenter 

Organization 

Registered Ballot Body Segment 
1

Additional
Member

Additional Organization

Region

PPL Electric Utilities Corporation

RFC

1

2. Brent Ingebrigtson

LG&E and KU Services Company

SERC

3

PPL Generation, LLC on behalf of its Supply NERC Registered
3. Annette M. Bannon
Entities

RFC

5

4.

WECC 5
PPL EnergyPlus, LLC

MRO

3

4

5

6

7

8

9

10

Segment
Selection

1. Brenda L. Truhe

5. Elizabeth A. Davis

2

6

6.

NPCC 6

7.

SERC

6

8.

SPP

6

9.

RFC

6

10.

WECC 6

8.

Group 

SERC Protection and Controls 
Subcommittee 

David Greene 

X 

X 

X 

X 

Additional Member Additional Organization Region Segment Selection
1. Paul Nauert

Ameren

2. Bridget Coffman

Santee Cooper

3. Steve Edwards

Dominion

4. Russ Evans

SCE&G

5. John Miller

Georga Transmission

6. Phil Winston

Southern Co

7. David Greene

SERC

9.

Group 

Jamison Dye 

Bonneville Power Administration 

Additional Member Additional Organization Region Segment Selection
1. Dean Bender

Technical Svcs

WECC 1

10.

Individual 

Bob Steiger 

Salt River Project 

X 

X 

X 

X 

11.

Individual 

Ryan Millard 

PacifiCorp 

X 

X 

X 

X 

12.

Individual 

Oliver Burke 

Entergy Services, Inc. (Transmission) 

X 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

6 

Group/Individual 

Commenter 

Organization 

Registered Ballot Body Segment 
1

2

3

4

5

6

7

8

9

10

13.

Individual 

Thad Ness 

American Electric Power 

X 

X 

X 

X 

14.

Individual 

Ed Croft 

Puget Sound Energy 

X 

X 

X 

15.

Individual 

Nazra Gladu 

Manitoba Hydro 

16.

Individual 

Michael Falvo 

Independent Electricity System Operator 

X 

X 

X 

X 

X 

17.

Individual 

Timothy Brown 

Idaho Power Co. 

X 

18.

Individual 

Dale Fredrickson 

Wisconsin Electric Power Company 

X 

X 

X 

19.

Individual 

Travis Metcalfe 

Tacoma Power 

X 

X 

X 

X 

X 

20.

Individual 

Bradley Collard 

Oncor Electric Delivery LLC 

X 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

7 

1. Do you agree with this scope? If not, please explain. 

Summary Consideration: 
Commenters were unclear about the division of responsibilities between the Generator Owner and Transmission Owner. Changes were 
made to both standards to address these concerns. Please refer to the summary changes to the proposed draft 2 of PRC‐023‐3 in the 
Consideration of Comments for draft 2 of PRC‐025‐1. 

Organization 
Northeast Power Coordinating Council 

Yes or No 

Question 1 Comment 

No 

The Industry Need statement, as written, implies that the burden of the 
overlap between PRC‐023‐3 and PRC‐025‐1 rests with the Generator 
Owner as the owner of the protection for the elements that connect the 
generator to the transmission system.  The intent of the drafting teams 
for PRC‐023‐3 and PRC‐025‐1 is to segregate the standards so that load‐
responsive relays used for generator protection are in one standard 
(PRC‐025‐1) and load‐responsive relays used to protect transmission are 
in another (PRC‐023‐3). 
The Applicability section of PRC 025‐1 refers to generator 
interconnected Facilities which can be construed to mean Generator 
Owners are responsible for this protection and the terminals at each 
end.  There are Transmission Owners that own protection assets on 
some, if not all of the terminals for a generator’s interconnection.  
Terminal responsibility needs clarification.  The wording places 
emphasis on asset ownership. 

Response: The drafting team thanks you for your comments. Responsibility is placed on the owner of load‐responsive protective 
relays. The Generator Owner function has been retained in the Applicability of PRC‐023‐3 to address configurations where the 
SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

8 

Organization 

Yes or No 

Question 1 Comment 

Generator Owner owns load‐responsive protective relays on the terminals of network transmission lines. In cases where the 
Distribution Provider or Transmission Owner owns load‐responsive protective relays on the terminals of generator 
interconnection Facilities such as a generator step‐up (GSU) transformer or generator interconnection Facility, the proposed draft 
2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution Provider or Transmission Owner may own 
relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides the criteria that the Distribution Provider 
or Transmission Owner shall use to set load‐responsive protective relays. Change made to the proposed draft 2 PRC‐023‐3 
standard. 
ACES Standards Collaborators 

No 

(1) In order to have a clear “bright line,” the generator owner should 
not apply to PRC‐023.Remove all reference to GO from PRC‐023, and 
then the SAR will satisfy the intent of avoiding double jeopardy. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Dominion 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

No 

Dominion believes the Industry Need as indicated in the SAR could be 
better stated. We believe the intent of the drafting teams for PRC‐023 
and PRC‐025 is to segregate the standards so that load‐responsive 
relays used for generator protection are in one standard (PRC‐025) and 
load‐responsive relays used to protect the bulk power system 
(Transmission as defined in the NERC Glossary; An interconnected group 
of lines and associated equipment for the movement or transfer of 
electric energy between points of supply and points at which it is 
9 

Organization 

Yes or No 

Question 1 Comment 
transformed for delivery to customers or is delivered to other electric 
systems.) are in another (PRC‐023). 
The SAR as written appears to infer that, in all cases, the GO owns the 
protection system that contains the load‐responsive relays that protect 
Transmission (as defined in the NERC Glossary) from faults that occur on 
the element(s) that make up the Facility used to connect the generator 
to Transmission. 
PRC 025 refers to generator interconnected Facilities (ie generator 
leads..some refer to this as GSU leads) which implies Generator Owners 
are responsible for this protection and the terminals at each end.  There 
are TOs that own “lead” assets either on both ends or possibly one end 
of the leads.  This is an area that needs further clarification when 
referring to terminal responsibility. Appears now that wording places 
emphasis on asset ownership? 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
PPL Corporation NERC Registered 
Affiliates 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

No 

The PPL Companies do not agree that addition of the phrase includes 
the specificity needed to ensure “double jeapordy” for generation. As 
stated by the North American Generators Forum standards review 

10 

Organization 

Yes or No 

Question 1 Comment 
team: 
Load‐responsive protective relays installed on the high side terminals of 
the Generator Step‐up transformer looking towards the Transmission 
system appear to be clearly in scope for PRC‐23‐3 but are not clearly 
excluded from being applicable to PRC‐025‐1. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Bonneville Power Administration 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

No 

The difference between “applied to circuits defined in 4.2.1” and 
“applied at the terminals of the circuits defined in 4.2.1” is not clear.  If 
there is any difference, it is subtle, and probably not worth revising PRC‐
023‐2 for.  The bigger problem is that transmission lines over 200kV that 
attach generating facilities to the BES seem to be covered by both PRC‐
023 and PRC‐025.  PRC‐025 applies to Generation interconnection 
Facilities, but there is no definition of this term.  It seems that a 230kV 
line that connects a GSU transformer to a substation would be 
considered to be a Generation interconnection facility, and subject to 
both standards. Therefore, there are two very different requirements 
that apply to the relays on such a line.  A definition of Generator 
interconnection Facilities is needed, and clarification of which standard 
the example given above would be covered by is needed. 

11 

Organization 

Yes or No 

Question 1 Comment 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Manitoba Hydro 

No 

(1) Similar to PRC‐025, the phrase “while maintaining reliable protection 
of the BES” is vague.  There are no objective criteria specified for this 
determination, nor is it clear whether this element will be audited in 
some fashion.  If this element of the requirement cannot be audited, it 
should be deleted.  At a minimum, it should specify that the Responsible 
Entity makes this determination in its sole discretion.  

Response: The drafting team agrees. The term, “while maintaining reliable fault protection” describes that the responsible entity 
is to comply with this standard while achieving their desired protection goals. This phrase is already approved language in PRC‐
023‐2. No change made. 
Wisconsin Electric Power Company 

No 

Adding this phrase does little to remove the confusion as to applicability 
to Generator Owners. 

Response: The drafting team thanks you for your comments. Generator Owner has been retained in the Applicability of PRC‐023‐
3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of network 
transmission lines. No change made. 
Tacoma Power 
SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

No 

The phrase “at the terminals of the” does not seem to mitigate the 

12 

Organization 

Yes or No 

Question 1 Comment 
potential overlap between PRC‐023 and PRC‐025.  Should not the 
distinction be drawn for generation interconnection Facility(ies)?  In 
other words, it seems that transmission lines only connecting 
generation would be subject to PRC‐025‐1 and that transmission lines 
that are part of the more interconnected transmission system would be 
subject to PRC‐023‐3.  If the Generator Relay Loadability Standard 
Drafting Team disagrees, additional clarification is requested as to how 
the phrase “at the terminals of the” mitigates the potential overlap. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Tennessee Valley Authority 

Yes 

Luminant 

Yes 

Southwest Power Pool Standards 
Development Team  

Yes 

SERC Protection and Controls 
Subcommittee 

Yes 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

13 

Organization 

Yes or No 

Question 1 Comment 

PacifiCorp 

Yes 

Salt River Project 

Yes 

Entergy Services, Inc. (Transmission) 

Yes 

American Electric Power 

Yes 

Puget Sound Energy 

Yes 

Independent Electricity System 
Operator 

Yes 

Idaho Power Co. 

Yes 

Oncor Electric Delivery LLC 

Oncor is not registered as a Generator Owner, nor does it perform the 
functions of a Generator Owner.  Thus, this question is not applicable to 
Oncor. 

Response: The drafting team thanks you for your participation. 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

14 

2. The SAR identifies a list of reliability functions that may be assigned responsibility for requirements in the set of standards 
addressed by this SAR. Do you agree with the list of proposed applicable functional entities? If no, please explain. 

Summary Consideration:   
Commenters were unclear about the division of responsibilities between the Generator Owner and Transmission Owner. Changes were 
made to both standards to address these concerns. Please refer to the summary changes to the proposed draft 2 of PRC‐023‐3 in the 
Consideration of Comments for draft 2 of PRC‐025‐1. Typographical errors raised in comments were addressed. 

Organization 
Northeast Power Coordinating 
Council 

Yes or No 
No 

Question 2 Comment 
The Reliability Functions table has the Planning Coordinator checked.  The 
Planning Coordinator by definition in the NERC Functional Model is “The 
functional entity that coordinates, facilitates, integrates and evaluates (generally 
one year and beyond) transmission facility and service plans, and resource plans 
within a Planning Coordinator area and coordinates those plans with adjoining 
Planning Coordinator areas.”  The Planning coordinator does not get involved 
with generator and transmission relay loadability.  

Response: The drafting team thanks you for your comments. PRC‐023‐3, Requirement R6 assigns the responsibility to the 
Planning Coordinator. No change made. 
ACES Standards Collaborators 

No 

(1) The purpose of the revised SAR is to remove the applicability of GOs for PRC‐
023‐2. Therefore, we recommend unselecting the Generator Owner box in the 
supplemental SAR, as the revised standard would not apply to GOs. 

Response: The drafting team thanks you for your comments. Generator Owner has been retained in the Applicability of PRC‐023‐
3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of network 
transmission lines. No change made. 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

15 

Organization 
Dominion 

Yes or No 
No 

Question 2 Comment 
Under 4.1.2 PRC 023‐2 needs to be changed to PRC023‐3. 

Response: The drafting team thanks you for your comments and has corrected the typographical error in the proposed PRC‐023‐
3. Correction made in the proposed PRC‐023‐3 standard. 
Bonneville Power 
Administration 

No 

BPA believes there needs to be a clearer delineation between generator facilities 
and transmission facilities and PRC‐023 and PRC‐025 written so that there is no 
overlap between the two.  Then the applicability of both PRC‐023 and PRC‐025 
can be easily applied to the owners of the facilities covered by that standard, 
whether they are registered as a GO, TO, or DP.  As PRC‐025 is proposed, it only 
applies to GO’s, but what if a TO owns the relays applied to a GSU transformer?  
These relays would presently not be covered by either PRC‐023 or PRC‐025. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Puget Sound Energy 

No 

Possibly the GO (section 4.1.2) should be taken out.  This function is covered in 
PRC‐025.  Taking the GO function out of PRC‐023 (and any accompanying items) 
would further strengthen the brightline between PRC‐023‐3 and PRC‐025‐1. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

16 

Organization 

Yes or No 

Question 2 Comment 

network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Wisconsin Electric Power 
Company 

No 

The applicability of this standard should be removed from the Generator Owner.  

Response: The drafting team thanks you for your comments. Generator Owner has been retained in the Applicability of PRC‐023‐
3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of network 
transmission lines. No change made. 
Manitoba Hydro 

Yes 

No comment. 

Tennessee Valley Authority 

Yes 

Luminant 

Yes 

Southwest Power Pool 
Standards Development Team  

Yes 

PPL Corporation NERC 
Registered Affiliates 

Yes 

SERC Protection and Controls 
Subcommittee 

Yes 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

17 

Organization 

Yes or No 

Question 2 Comment 

PacifiCorp 

Yes 

Salt River Project 

Yes 

Entergy Services, Inc. 
(Transmission) 

Yes 

American Electric Power 

Yes 

Independent Electricity 
System Operator 

Yes 

Idaho Power Co. 

Yes 

Tacoma Power 

Yes 

Oncor Electric Delivery LLC 

Oncor is not registered as a Generator Owner, nor does it perform the functions 
of a Generator Owner.  Thus, this question is not applicable to Oncor. 

Response: The drafting team thanks you for your participation. 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

18 

3. Do the proposed changes in the draft PRC‐023‐3 – Transmission Relay Loadability create the necessary bright line between the 
draft PRC‐025‐1 – Generator Relay Loadability create the bright line between the two standards? If no, please explain what would 
make the bright line clearer. 

Summary Consideration: 
Commenters were unclear about the division of responsibilities between the Generator Owner and Transmission Owner. Changes were 
made to both standards to address these concerns. Please refer to the summary changes to the proposed draft 2 of PRC‐023‐3 in the 
Consideration of Comments for draft 2 of PRC‐025‐1. Typographical errors raised in comments were addressed. 

Organization 
Tennessee Valley Authority 

Yes or No 

Question 3 Comment 

No 

Though the line could be derived from reading the purpose of the standard, it 
may help avoid potential confusion to the generator owners by specifically 
excluding generator step‐up units from 4.2.1.6 or the second bullet of Attachment 
B. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Northeast Power Coordinating 
Council 

No 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

The draft SAR and proposed standards PRC‐023‐3, PRC‐025‐1 fail to provide a 
clear distinction as to whether the standard is meant to apply to the owner of a 
protection system designed to protect transmission elements (which we believe is 
19 

Organization 

Yes or No 

Question 3 Comment 
the intent of PRC‐023‐3), or the owner of a protection system designed to protect 
generation elements (which we believe is the intent of PRC‐025‐1).  We believe 
this was the intent, but the applicability section of either of the proposed 
standards does not clearly articulate that intent. 
Suggest the SDT consider an approach similar to that used in PRC‐006‐1 where 
the SDT chose to create a ‘standard specific entity’; UFLS entities. 
Alternatively, the applicability could be modified to more closely match the intent 
indicated in the Applicability section of the Guideline and Technical Basis 
document, and in the wording of the Supplemental SAR for Project 2010‐13.2 
Relay Loadability Order 733 Phase 2 (Relay Loadability: Generation). The standard 
should be applied to the owner of the particular type of protection system, not 
applied to a particular function.  
We are aware of circumstances whereby an entity registered as Transmission 
Owner owns the protection system that protects for faults on the element(s) 
owned by an entity registered as a Generator Owner which are solely used to 
interconnect their generator to the bulk power system. 
We are also aware of circumstances whereby the Generator Owner owns both 
the element(s) which are solely used to interconnect their generator to the bulk 
power system as well as the protection system that protects for faults on those 
generator interconnection element(s). 
In both of these, the protection system is designed to protect the bulk power 
system from the fault, not the generator itself. Changes to proposed PRC 023‐2 
and PRC 025‐1 attempt to establish a bright line, but the functional entity of 
Generator Owners is still included in PRC 023‐3.  This results in confusion as to 
what standard applies for the elements that connect the generator to the BES, as 
some Transmission Owners own GSU assets.  The wording of PRC‐025‐1, and as 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

20 

Organization 

Yes or No 

Question 3 Comment 
stated in the Webinar, imply that “leads assets” will fall under PRC‐025‐1. There is 
still confusion in this area so a bright line still has not been established. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Southwest Power Pool 
Standards Development Team  

No 

While we agree that the revision to PRC023‐2 creates a bright line we feel that 
language should be included in PRC‐25‐1 to clearly state that the protection relays 
under PRC023‐2 ,or ‐3 if the SAR is approved, would be not be applicable under 
PRC025‐1. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
ACES Standards Collaborators 

No 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

See comments above. There should not be any references to generators in the 
transmission loadability standard. 

21 

Organization 

Yes or No 

Question 3 Comment 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Dominion 

No 

The draft SAR and proposed standards PRC‐023‐3, PRC‐025‐1 fail to provide a 
clear distinction as to whether the standard is meant to apply to the owner of a 
protection system designed to protect transmission elements (which we believe is 
the intent of PRC‐023) or the owner of a protection system designed to protect 
generation elements (which we believe is the intent of PRC‐025). We believe this 
was the intent of the SDT but we don’t believe the applicability section of either 
of the proposed standards clearly articulates that intent. 
We suggest the SDT consider an approach similar to that used in PRC‐006‐1 where 
the SDT chose to create a ‘standard specific entity’; UFLS entities. 
Alternatively, the applicability could be modified to more closely match the intent 
as indicated in the Applicability section of the Guideline and Technical Basis 
document and the Supplemental SAR for Project 2010‐13.2 Relay Loadability 
Order 733 Phase 2 (Relay Loadability: Generation). We believe the standard 
should be applied to the owner of the particular type of protection system, not 
applied to a particular function. 
We are aware of circumstances whereby an entity registered as TO owns the 
protection system that protects for faults on the element(s) owned by an entity 
registered as a GO which are solely used to interconnect their generator to the 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

22 

Organization 

Yes or No 

Question 3 Comment 
bulk power system. 
We are also aware of circumstances whereby the GO owns both the element(s) 
which are solely used to interconnect their generator to the bulk power system as 
well as the protection system that protects for faults on those generator 
interconnection element(s). 
In both of these, the protection system is designed to protect the bulk power 
system from the fault, not the generator itself. Changes to proposed PRC 023‐2 
and PRC 025‐1 attempts to establish a bright line but the functional entity of 
Generator Owners is still included in PRC 023 so this results in confusion as to 
what standard applies for the elements that connect the generator to the BES as 
some Transmission Owners own GSU assets but the new standard and as stated 
on the Webinar it implies that “leads assets” will fall under PRC 025. There is still 
confusion in this area so a bright line still has not been established. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Bonneville Power 
Administration 

No 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

As described in comments 1 and 2, BPA believes there needs to be a definition of 
“Generator interconnection Facilities” if this term will be used in PRC‐025.  There 
needs to be a clear separation between facilities included in PRC‐023 and those 
included in PRC‐025, with no overlap. 

23 

Organization 

Yes or No 

Question 3 Comment 
The most likely place for this separation would be at the high‐voltage terminal of 
the GSU transformer, with the GSU and everything between it and the generators 
included in PRC‐025, and the line connecting the GSU to the BES included in PRC‐
023. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
American Electric Power 

No 

AEP believes that the proposed changes in the draft PRC‐023‐3 create a bright line 
identifying the scope of PRC‐023‐3. 
However, the proposed draft of PRC‐025‐1 does not create a bright line 
identifying the scope of PRC‐025‐1.  Load‐responsive protective relays installed on 
the high side terminals of the Generator Step‐Up transformer looking towards the 
Transmission system are clearly in scope for PRC‐023‐3 but are not clearly 
excluded from being applicable from PRC‐025‐1. 
AEP recommends including in PRC‐025‐1 verbiage clearly excluding load‐
responsive protective relays applicable to PRC‐023‐3 from PRC‐025‐1. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

24 

Organization 

Yes or No 

Question 3 Comment 

interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Puget Sound Energy 

No 

see answer to question 2 

Response: The drafting team thanks you for your comments; please refer to the above response(s) in question 2. 
Manitoba Hydro 

No 

(1) In section 4.1.1, 4.1.2 and 4.1.3, the redlined part “at the terminals of” should 
be changed to “at the Transmission Owner terminals of”, “at the generator owner 
terminals of” and “at the Distribution Owner terminals of”.  Also, PRC‐023‐2 in 
section 4.1.2 should be changed to PRC‐023‐3.  

Response: The drafting team has included additional explanation in the PRC‐025‐1 Guidelines and Technical Basis document and 
made several changes to both drafts of PRC‐023‐3 and PRC‐025‐1 to address these concerns and has corrected the typographical 
error from version ‐2 to version ‐3. Correction made to the proposed PRC‐023‐3 standard. 
Wisconsin Electric Power 
Company 

No 

Any requirements applicable to the Generator Owner should be in a single 
standard, PRC‐025‐1.  When this standard is approved, Generator Owners that 
employ load‐sensitive relaying on the high‐voltage side of the generator step‐up 
transformer, between the GSU and the interconnection with the Transmission 
system, will be subject to the PRC‐025‐1 requirements in 3.2.4 for Generator 
interconnection Facilities, and at that time the PRC‐023 standard should have all 
applicability to Generator Owners removed. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

25 

Organization 

Yes or No 

Question 3 Comment 

relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Tacoma Power 

No 

The phrase “at the terminals of the” does not seem to mitigate the potential 
overlap between PRC‐023 and PRC‐025.  Should not the distinction be drawn for 
generation interconnection Facility(ies)?  In other words, it seems that 
transmission lines only connecting generation would be subject to PRC‐025‐1 and 
that transmission lines that are part of the more interconnected transmission 
system would be subject to PRC‐023‐3.  If the Generator Relay Loadability 
Standard Drafting Team disagrees, additional clarification is requested as to how 
the phrase “at the terminals of the” mitigates the potential overlap. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
PPL Corporation NERC 
Registered Affiliates 

No 

Luminant 

Yes 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

26 

Organization 

Yes or No 

Question 3 Comment 

SERC Protection and Controls 
Subcommittee 

Yes 

PacifiCorp 

Yes 

Salt River Project 

Yes 

Entergy Services, Inc. 
(Transmission) 

Yes 

Independent Electricity 
System Operator 

Yes 

Idaho Power Co. 

Yes 

Oncor Electric Delivery LLC 

Oncor is not registered as a Generator Owner, nor does it perform the functions 
of a Generator Owner.  Thus, this question is not applicable to Oncor. 

Response: The drafting team thanks you for your participation. 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

27 

4. Are you aware of any regional variances that will be needed as a result of this project? If yes, please identify the regional variance. 

Summary Consideration: 
No regional variances were identified. 

Organization 

Yes or No 

Question 4 Comment 

Manitoba Hydro 

No 

No comment. 

Tennessee Valley Authority 

No 

Northeast Power Coordinating 
Council 

No 

Luminant 

No 

Southwest Power Pool 
Standards Development Team  

No 

ACES Standards Collaborators 

No 

Dominion 

No 

PPL Corporation NERC 
Registered Affiliates 

No 

SERC Protection and Controls 
Subcommittee 

No 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

28 

Organization 

Yes or No 

Question 4 Comment 

Bonneville Power 
Administration 

No 

PacifiCorp 

No 

Salt River Project 

No 

Entergy Services, Inc. 
(Transmission) 

No 

American Electric Power 

No 

Puget Sound Energy 

No 

Independent Electricity 
System Operator 

No 

Idaho Power Co. 

No 

Wisconsin Electric Power 
Company 

No 

Tacoma Power 

No 

Oncor Electric Delivery LLC 

Oncor is not registered as a Generator Owner, nor does it perform the functions of 
a Generator Owner.  Thus, this question is not applicable to Oncor. 

Response: The drafting team thanks you for your participation. 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

29 

5. Are you aware of any business practice that will be needed or that will need to be modified as a result of this project? If yes, please 
identify the business practice. 

Summary Consideration: 
Commenters were unclear about the division of responsibilities between the Generator Owner and Transmission Owner. Changes were 
made to both standards to address these concerns. Please refer to the summary changes to the proposed draft 2 of PRC‐023‐3 in the 
Consideration of Comments for draft 2 of PRC‐025‐1. Typographical errors raised in comments were addressed including the re‐inserting 
the Implementation Plan for the proposed PRC‐023‐3. 

Organization 
SERC Protection and Controls 
Subcommittee 

Yes or No 
No 

Question 5 Comment 
There may be owner issues that impact entity registration.     

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of 
PRC‐023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of 
network transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective 
relays on the terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator 
interconnection Facility, the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution 
Provider or Transmission Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides 
the criteria that the Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made 
to the proposed draft 2 PRC‐023‐3 standard. 
Manitoba Hydro 

No 

No comment. 

Idaho Power Co. 

No 

There will obviously be additional work to perform the analysis needed to be 
compliant with the standard.  The only business practice that will need to be 
modified is to perform this analysis for any new or modified generators or 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

30 

Organization 

Yes or No 

Question 5 Comment 
generator protective relays to ensure compliance. 

Response: The drafting team thanks you for your comment. 
Tennessee Valley Authority 

No 

Northeast Power Coordinating 
Council 

No 

Luminant 

No 

Southwest Power Pool 
Standards Development Team  

No 

ACES Standards Collaborators 

No 

Dominion 

No 

PPL Corporation NERC 
Registered Affiliates 

No 

Bonneville Power 
Administration 

No 

PacifiCorp 

No 

Salt River Project 

No 

American Electric Power 

No 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

31 

Organization 

Yes or No 

Question 5 Comment 

Puget Sound Energy 

No 

Independent Electricity 
System Operator 

No 

Wisconsin Electric Power 
Company 

No 

Tacoma Power 

No 

Entergy Services, Inc. 
(Transmission) 

Yes 

Elimination of the table under number 5 of section A in PRC‐023‐2.  

Response: The drafting team thanks you for your comments and has re‐inserted the Implementation Plan information under the 
proposed draft 2 of the PRC‐023‐3 standard, Section A, Item 5. Change made to the Implementation Plan. 
Oncor Electric Delivery LLC 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

No Comment 

32 

6. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here: 
Summary Consideration: 
Commenters were unclear about the division of responsibilities between the Generator Owner and Transmission Owner. Changes were 
made to both standards to address these concerns. Please refer to the summary changes to the proposed draft 2 of PRC‐023‐3 in the 
Consideration of Comments for draft 2 of PRC‐025‐1. Typographical errors raised in comments were addressed including the re‐inserting 
the Implementation Plan for the proposed PRC‐023‐3. 

Organization 

Yes or No 

SERC Protection and Controls 
Subcommittee 

Question 6 Comment 
‐ It needs to be clear that 'at the terminals' does not imply ownership.  Entities may 
be responsible for protective relays on each end of the leads but may be in facilities 
where one end is owned by a TO and the other end facility is owned by a GO. 
Response: The drafting team agrees and the proposed PRC‐023‐3 standard makes 
this distinction clear. No change made. 
‐ The removal of the “Effective Dates” table needs to be reexamined.  Among other 
things, this table included the timelines for meeting PRC‐023 on sub‐200kV Facilities.  
If a sub‐200kV Facility is identified by the Planning Coordinator, pursuant to 
Requirement R6, Transmission Owners, Generator Owners, and Distribution 
Providers must be given a grace period in which to make protection modifications 
before PRC‐023 is applicable to that Facility.  PRC‐023‐2 included a 39‐month window 
for modifying these Facilities once they’ve been identified by the Planning 
Coordinator. This is an oversight that will cause confusion. 
Response: The drafting team thanks you for your comments and has re‐inserted the 
implementation plan information under the proposed draft 2 of the PRC‐023‐3 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

33 

Organization 

Yes or No 

Question 6 Comment 
standard, Section A, Item 5. Change made to the proposed PRC‐023‐3 
Implementation Plan. 
The comments expressed herein (Questions 1‐6) represent a consensus of the views 
of the above‐named members of the SERC EC Protection and Control Subcommittee 
only and should not be construed as the position of SERC Reliability Corporation, its 
board, or its officers. 

Response: The drafting team thanks you for your comments; please refer to the above response(s). 
ACES Standards Collaborators 

(1) We disagree with including GOs as an applicable entity to PRC‐023‐2. In order to 
create a “bright line,” the drafting teams should have separate standards. Have PRC‐
023 apply to transmission and have PRC‐025 apply to generators. It is a simple 
dividing line. If the team feels that any of the loadability criteria from the 
transmission loadability standard should be included in PRC‐025, then do so, but do 
not leave any reference to GOs in PRC‐023. 
(2) With the proposed PRC‐023‐3, there is overlap for GOs. The GO is listed in all six 
requirements in PRC‐023 and in R1 of PRC‐025. We recommend removing all 
references to GOs in PRC‐023.If this cannot be accomplished, then update PRC‐023‐3 
to include the aspects of PRC‐025 and stop developing a duplicative standard. 

Response: The drafting team thanks you for your comments. Generator Owner function has been retained in the Applicability of PRC‐
023‐3 to address configurations where the Generator Owner owns load‐responsive protective relays on the terminals of network 
transmission lines. In cases where the Distribution Provider or Transmission Owner owns load‐responsive protective relays on the 
terminals of generator interconnection Facilities such as a generator step‐up (GSU) transformer or generator interconnection Facility, 
the proposed draft 2 of PRC‐023‐3 Applicability has been revised to address Facilities the Distribution Provider or Transmission 
Owner may own relative to generating plants. The proposed draft 2 of the PRC‐023‐3 standard provides the criteria that the 
Distribution Provider or Transmission Owner shall use to set load‐responsive protective relays. Change made to the proposed draft 2 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

34 

Organization 

Yes or No 

Question 6 Comment 

PRC‐023‐3 standard. 
American Electric Power 

AEP believes there is a typo in PRC‐023‐3 Section 4.1.2.  The statement references 
PRC‐023‐2 instead of the current standard revision.  

Response: The drafting team thanks you for your comment and has corrected the typographical error from version ‐2 to version ‐3. 
Correction made to the proposed PRC‐023‐3 standard. 
Entergy Services, Inc. 
(Transmission) 

Comments to NERC on Proposed PRC‐023‐3 Standard 
It is understood that PRC‐023‐3 is intended to replace PRC‐023‐1 and PRC‐023‐2 in 
the near future. The changes proposed for PRC‐023‐3 in comparison with PRC‐023‐2 
are mainly the removal of the table under number 5 of section A. The table being 
removed provides the effective dates of the requirements in the PRC‐023‐2 standard 
corresponding to the applicable Functional Entities and circuits. Entergy has concerns 
over the removal of the table as explained below. 
Our specific area of concern is on the effective date of PRC‐023‐3 which is defined in 
the standard as the “first day of the first calendar quarter beyond the date that this 
standard is approved by applicable regulatory authorities”. (See the bottom of page 1 
of the proposed PRC‐023‐3 standard.) 
In the Implementation Plan for the proposed PRC‐023‐3 standard, it is stated that 
entities applicable to this standard shall be 100% compliant on the effective date of 
the standard. (See the last line on page 2 of the Implementation Plan.) 
In other words, the Implementation Plan considers a specific implementation period 
as not required based on the following two reasons. (See section General 
Considerations at the bottom of page 1 of the Implementation Plan.) 
1. No new entity or facilities are subject to compliance. 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

35 

Organization 

Yes or No 

Question 6 Comment 
2. The implementation plan and period for PRC‐023‐2 will have been achieved. 
Entergy sees some scenarios that do not agree with either or both of the above 
reasons. In such scenarios, the PRC‐023‐3 effective date and Implementation Plan 
become problematic.  
In short, PRC‐023‐3 proposes to retroactively eliminate the NERC‐defined 
implementation time for ongoing PRC‐023‐2 compliance activities. A couple of 
scenarios are provided below for illustration purposes. 
The first scenario is related to the effective date of requirements R6 and R1 of PRC‐
023‐2. PRC‐023‐2 became effective in the United States on July 1, 2012. (See the 
Background section on page 1 of the Implementation Plan for PRC‐023‐3.) However, 
PRC‐023‐2 gives various effective dates that are to be phased in over the period of 
more than four years. According to the table on pages 2‐4 of the PRC‐023‐2 standard, 
R6 will become effective on 1/1/2014. For circuits identified by the Planning 
Coordinator pursuant to Requirement R6, R1 is to be effective 39 months following 
notification by the Planning Coordinator of their inclusion on a list of circuits subject 
to PRC‐023‐2 per application of Attachment B. It means that the applicable entity is 
given 39 months to develop and implement a plan to bring the applicable circuits to 
compliance. Therefore, the compliance date can be as late as 4/1/2017 or beyond 
depending on when the Planning Coordinator will send out its notification on 
applicable circuits. 
If PRC‐023‐3 becomes effective before such date, it will be problematic. For 
reference, the relevant effective dates for R6 and R1 as specified in PRC‐023‐2(Please 
review Effective Dates as provided in table for NERC Standard PRC‐023‐2).      The 
second scenario is about new circuits identified by Planning Coordinator during its 
assessments that are required to be conducted at least once each calendar year 
pursuant to R6 of PRC‐023‐3. (See the middle of page 4 of the PRC‐023‐3 standard.) 
When new circuits are identified as the result of the yearly assessment, applicable 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

36 

Organization 

Yes or No 

Question 6 Comment 
entities will need reasonable amount of time to bring the circuit to compliance. This 
time period is necessary for budget reasons as well as project planning and 
construction reasons. While both PRC‐023‐1 and PRC‐023‐2 recognize such a need, 
the proposed standard PRC‐023‐3 does not. (See section 5.1.3 on page 1 of PRC‐023‐
1 and effective date table on pages 2‐4 of PRC‐023‐2.) 
Entergy suggests that a 39 months long period of time be given to applicable entities 
to comply with the PRC‐023‐3 standard for each facility that is added to the Planning 
Coordinator’s list. Please review the referenced NERC standard documents. 
1) NERC Standard PRC‐023‐1 
2) NERC Standard PRC‐023‐2 
3) NERC Proposed Standard PRC‐023‐3 (clean) 
4) NERC PRC‐023‐3 Implementation Plan 

Response: The drafting team thanks you for your comments and has re‐inserted the implementation plan information under the 
proposed draft 2 of the PRC‐023‐3 standard, Section A, Item 5. Change made to the proposed PRC‐023‐3 Implementation Plan. 
Dominion 

It needs to be clear that at the terminals does not imply ownership.  Entities may be 
responsible for protective relays on each end of the leads but may be in facilities 
where one end is owned by a TO and the other end facility is owned by a GO.  
Response: The drafting team agrees and the proposed PRC‐023‐3 standard makes 
this distinction clear. No change made. 
‐The removal of the “Effective Dates” table needs to be reexamined.  Among other 
things, this table included the timelines for meeting PRC‐023 on sub‐200kV Facilities.  
If a sub‐200kV Facility is identified by the Planning Coordinator, pursuant to 
Requirement R6, Transmission Owners, Generator Owners, and Distribution 
Providers must be given a grace period in which to make protection modifications 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

37 

Organization 

Yes or No 

Question 6 Comment 
before PRC‐023 is applicable to that Facility.  PRC‐023‐2 included a 39‐month window 
for modifying these Facilities once they’ve been identified by the Planning 
Coordinator. This is an oversight that will cause confusion. 
Response: The drafting team thanks you for your comments and has re‐inserted the 
implementation plan information under the proposed draft 2 of the PRC‐023‐3 
standard, Section A, Item 5. Change made to the propose PRC‐023‐3 Implementation 
Plan. 

Response: The drafting team thanks you for your comments; please refer to the above response(s). 
Northeast Power Coordinating 
Council 

It needs to be made clear that owning the protection systems at the terminals does 
not imply ownership of the facility.  Entities may be responsible for protective relays 
on each end of a “lead”, but the leads but may be in facilities where one end is 
owned by a Transmission Owner, and the other end facility is owned by a Generator 
Owner. 
Response: The drafting team agrees and the proposed PRC‐023‐3 standard makes 
this distinction clear. No change made. 
The removal of the “Effective Dates” table needs to be re‐examined.  Among other 
things, this table included the timelines for meeting PRC‐023 on sub‐200kV Facilities.  
If a sub‐200kV Facility is identified by the Planning Coordinator, pursuant to 
Requirement R6, Transmission Owners, Generator Owners, and Distribution 
Providers must be given a grace period in which to make protection modifications 
before PRC‐023 is applicable to that Facility.  PRC‐023‐2 included a 39‐month window 
for modifying these Facilities once they’ve been identified by the Planning 
Coordinator. This is an oversight that will cause confusion. 
Response: The drafting team thanks you for your comments and has re‐inserted the 
implementation plan information under the proposed draft 2 of the PRC‐023‐3 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

38 

Organization 

Yes or No 

Question 6 Comment 
standard, Section A, Item 5. Change made to the proposed PRC‐023‐3 
Implementation Plan. 
In PRC‐023‐3, in 4.1.2 PRC 023‐2 needs to be changed to PRC‐023‐3. 
Response: The drafting team thanks you for your comment and has corrected the 
typographical error from version ‐2 to version ‐3. Correction made to the proposed 
PRC‐023‐3 standard. 

Response: The drafting team thanks you for your comments; please refer to the above response(s). 
Salt River Project 

No Comment 

Manitoba Hydro 

No comment. 

PacifiCorp 

Section 4.1 states that the Transmission Owner, Generator Owner, and Distribution 
Provider with load‐responsive phase protection systems at the terminal of the circuits 
is responsible for ensuring compliance with PRC‐023‐3.  PacifiCorp maintains that 
more clarification is needed with respect to who is ultimately responsible for 
ensuring compliance in instances where the circuit/transmission line has a different 
owner.  Would the owner of the circuit/transmission line rely on the owner of the 
relays for ensuring compliance? 

Response: The drafting team agrees and the proposed PRC‐023‐3 standard makes this distinction clear. The proposed PRC‐023‐3 
standard (and proposed PRC‐025‐1) is based on ownership of the load‐responsive protective relay, not the owner of the terminal or 
line. No change made. 
Oncor Electric Delivery LLC 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

The phase‐in time for a newly declared critical circuit was removed from the draft 
PRC‐023‐3 Effective Dates section; the phase‐in time needs to be added back to PRC‐
023‐3.  As written in PRC‐023‐2, R6 requires Planning Coordinators to conduct an 

39 

Organization 

Yes or No 

Question 6 Comment 
assessment of critical circuits on a periodic basis and provide “new circuits” to the 
appropriate registered entity. The Effective Dates section of PRC‐023‐2 states a 
registered entity will have 39 months to comply for newly declared critical circuits 
following declaration by the Planning Coordinator. This phase‐in time period provides 
necessary time for a registered entity to budget and implement a project to meet 
PRC‐023‐2 compliance. The 39 month phase‐in period was an acceptable and 
approved timeframe and should be added back to PRC‐023‐3. 

Response: The drafting team thanks you for your comment and has re‐inserted the Implementation Plan information under the 
proposed draft 2 of the PRC‐023‐3 standard, Section A, Item 5. Change made to the proposed PRC‐023‐3 Implementation Plan. 

END OF REPORT 

SAR Consideration of Comments: Project 2010‐13.2 
PRC‐023‐3| April 24, 2013 

40 

Standard PRC-023-3 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for formal comment on January 25, 2013.
Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 1 of
PRC-023-3 – Transmission Relay Loadability for a 30-day formal comment period.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

August 2013

10-day Recirculation Ballot

October 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version

Date

Action

Change
Tracking

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

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Revision

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Standard PRC-023-3 — Transmission Relay Loadability

Version

Date

Action

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Change
Tracking
Revision (Project
2010-13)

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1,
4.2.3, or 4.2.4 (Circuits Subject to Requirements R1 – R5, R7, and R8).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1,
4.2.3, or 4.2.4 (Circuits Subject to Requirements R1 – R5, R7, and R8), provided
those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinator
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 below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES
4.2.3 Circuits Subject to Requirement R7
4.2.3.1 Transmission lines that are used solely to export energy directly from a
BES generating unit or generating plant to the network.

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Standard PRC-023-3 — Transmission Relay Loadability
4.2.4 Circuits Subject to Requirement R8
4.2.4.1 Transformers with low voltage terminals connected below 200 kV,
including generator step-up transformers, that are used solely to export
energy directly from a BES generating unit or generating plant to the
network.
5. Effective Dates: See Implementation Plan
.
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 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, 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. Not used.

1

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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
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 capability2.
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 temperature3.
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.

2

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
3

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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.
R7. Each Transmission Owner and Distribution Provider shall set their load responsive relays in
accordance with PRC-023-3, Attachment C at the terminals of the generator interconnection
Facility. [Violation Risk Factor: High] [Time Horizon: Long Term Planning].
R8. Transmission Owner and Distribution Provider shall set their load responsive relays in
accordance with PRC-023-3, Attachment C at the terminals of the generator step-up transformer.
[Violation Risk Factor: High] [Time Horizon: Long Term Planning].

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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.
M7. Each Transmission Owner and Distribution Provider shall have evidence (e.g., summaries of
calculations, spreadsheets, simulation reports, or setting sheets) to show that each of its
generator interconnection Facility relays is set according to one of the criteria in Attachment C.
(R7)
M8. Each Transmission Owner and Distribution Provider shall have evidence (e.g., summaries of
calculations, spreadsheets, simulation reports, or setting sheets) to show that each of its
generator step-up transformer relays is set according to one of the criteria in Attachment C.
(R8)

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Standard PRC-023-3 — Transmission Relay Loadability

D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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, R7, and R8 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 Enforcement Authority 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.

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Standard PRC-023-3 — Transmission Relay Loadability

2.

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.

R2

R3

N/A

N/A

N/A

N/A

Project 2010-13.2 Phase 2 Relay Loadability (Draft 2: April 24, 2013)

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

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 7, 8, 9,
12, or 13 did not use the calculated
circuit capability as the Facility
Rating of the circuit.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

Project 2010-13.2 Phase 2 Relay Loadability (Draft 2: April 24, 2013)

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.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

Project 2010-13.2 Phase 2 Relay Loadability (Draft 2: April 24, 2013)

High
months or more 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 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)

Severe
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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

(part 6.2)

Severe
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 the standard.

R7

R8

N/A

N/A

N/A

N/A

Project 2010-13.2 Phase 2 Relay Loadability (Draft 2: April 24, 2013)

N/A

The responsible entity did not set
one of its generator
interconnection Facility relays in
accordance with the criteria in
Attachment C.

N/A

The responsible entity did not set
one of its generator step-up
transformer relays in accordance
with the criteria in Attachment C.

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Standard PRC-023-3 — 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

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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. Protective relays applied at the terminals of generation Facilities in accordance with NERC
Reliability Standard PRC-025-1 or its successor(s).
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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 analyses4 performed by the Planning Coordinator for the one-tofive-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.
4

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

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Standard PRC-023-3 — 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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — Attachment C
The following criteria shall be used to set load-responsive relays on generator interconnection Facilities and generator-step-up transformers.
This standard does not require the responsible entity to use any of the protective functions listed in Table 1. Each responsible entity that applies
load-responsive protective relays on Facilities listed in 4.2.3 and 4.2.4, Facilities shall use one of the following Options 1-12 in Table 1, Relay
Loadability Evaluation Criteria (“Table 1”), to set each load-responsive protective relay element according to its application and relay type. The
bus voltage is based on the criteria for the various applications listed in Table 1.
Relay pickup setting criteria values related to synchronous generators are derived from the unit’s maximum gross Real Power capability, in
megawatts (MW), as reported to the Transmission Planner or other entity as specified by the Regional Reliability Organization (RRO), and the
unit’s Reactive Power capability, in megavoltampere-reactive (Mvar), is determined by calculating the MW value based on the unit’s nameplate
megavoltampere (MVA) rating at rated power factor. If different seasonal capabilities are reported, the maximum capability shall be used for the
purposes of this standard.
Relay pickup setting criteria values related to asynchronous generators (including inverter-based installations) are derived from the site’s aggregate
maximum complex power capability, in MVA, as reported to the Transmission Planner or other entity as specified by the Regional Reliability
Organization (RRO), including the Mvar output of any static or dynamic reactive power devices.
For the application case where synchronous and asynchronous generator types are combined on a generator step-up transformer or on a generator
interconnection Facility, the pickup setting criteria shall be determined by vector summing the pickup setting criteria of each generator type, and
using the bus voltage for the given synchronous generator application and relay type.
Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers
with deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest
generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU
turns ratio shall be used.
Any relay elements that are in service only during start up, when the generator is disconnected, or when other Protection System components fail
are excluded. Examples of exclusions include, but are not limited to, the following:
Load-responsive protective relay elements that are armed only when the generator is disconnected from the system, (e.g., non-directional
overcurrent elements used in conjunction with inadvertent energization schemes, and open breaker flashover schemes),
Phase fault detector relay elements employed to supervise other load-responsive phase distance elements (in order to prevent false
operation in the event of a blown secondary fuse) provided the distance element is set in accordance with the criteria outlined in the
standard,
Table 1
The Table is structured and formatted to aid the reader with identifying an option for a given load-responsive protective relay.
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Standard PRC-023-3 — Transmission Relay Loadability
The first column identifies the application (e.g., generator step-up transformers and generator interconnection Facilities). Dark blue horizontal
bars, excluding the header which repeats at the top of each page, demarcate the various applications.
The second column identifies the load-responsive protective relay (e.g., 21, 51, or 67) according to the applied application in the first column. A
light blue horizontal bar between the relay types is the demarcation between relay types for a given application. These light blue bars will contain
no text.
The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting load-responsive
protective relays according to the application and applied relay type. Another, shorter, light blue bar contains the word “OR,” and reveals to the
reader that the relay for that application has one or more options (i.e., “ways”) to determine the bus voltage and pickup setting criteria in the fourth
and fifth column, respectively. The bus voltage column and pickup setting criteria columns provide the criteria for determining an appropriate
setting.
The table is further formatted by alternately shading groups of relays within a similar application. Also, intentional buffers were added to the table
such that similar options would be paired together on a per page basis. Note that some applications may have additional pairing that might occur
on adjacent pages.

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

1a

Generator stepup transformer
connected to
synchronous
generators

Phase distance
relay (21) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 7

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

1b

OR

1c

The same application continues on the next page with a different relay type

5

Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with
deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When
the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU turns ratio shall be used.

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

2a

Generator stepup transformer
connected to
synchronous
generators

Phase time
overcurrent relay
(51) – installed on
generator-side of
GSU
If the relay is
installed on the
high-side of GSU
use Option 8

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

2b

OR

2c

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

3a

Generator stepup transformer
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system– installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 9

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

3b

OR

3c

A different application starts on the next page

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Generator stepup transformer
connected to
asynchronous
generators only
(including
inverter-based
installations)

Relay Type
Phase distance
relay (21) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 10

Phase time
overcurrent relay
(51) – installed on
generator-side of
GSU
If the relay is
installed on the
high-side of GSU
use Option 11

Option

Bus Voltage5

Pickup Setting Criteria

4

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated impedance
derived from 130% of the maximum aggregate nameplate MVA
output at rated power factor (including the Mvar output of any static or
dynamic reactive power devices)

5

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer
for overcurrent relays installed on the
low-side

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 12

6

Bus Voltage5

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Pickup Setting Criteria

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

A different application begins below

7a

Generator
interconnection
Facilities
connected to
synchronous
generators

Phase distance
relay (21) –
directional toward
the Transmission
system

0.85 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

7b

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

8a

Phase time
overcurrent relay
(51)

Generator
interconnection
Facilities
connected to
synchronous
generators

Bus Voltage5

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

8b

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

9a
Generator
interconnection
Facilities
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system

Bus Voltage5

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

9b

A different application starts on the next page

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type
Phase distance
relay (21) –
directional toward
the Transmission
system

Generator
interconnection
Facilities
connected to
asynchronous
generators only
(including
inverter-based
installations)

Phase time
overcurrent relay
(51)

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system

Option

Bus Voltage5

Pickup Setting Criteria

10

1.0 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated impedance
derived from 130% of the maximum aggregate nameplate MVA
output at rated power factor (including the Mvar output of any static or
dynamic reactive power devices)

11

1.0 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

12

1.0 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

End of Table 1

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Standard PRC-023-3 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for formal comment on January 25, 2013.
Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 1 of
PRC-023-3 – Transmission Relay Loadability for a 30-day formal comment period.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

August 2013

10-day Recirculation Ballot

October 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version

Date

Action

Change
Tracking

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

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Revision

1

Standard PRC-023-3 — Transmission Relay Loadability

Version

Date

Action

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Change
Tracking
Revision (Project
2010-13)

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1,
4.2.3, or 4.2.4 (Circuits Subject to Requirements R1 – R5, R7, and R8).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-23 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1,
4.2.3, or 4.2.4 (Circuits Subject to Requirements R1 – R5, R7, and R8), provided
those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinator
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 below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES
4.2.3 Circuits Subject to Requirement R7
4.2.3.1 Transmission lines that are used solely to export energy directly from a
BES generating unit or generating plant to the network.
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Standard PRC-023-3 — Transmission Relay Loadability
4.2.4 Circuits Subject to Requirement R8
4.2.4.1 Transformers with low voltage terminals connected below 200 kV,
including generator step-up transformers, that are used solely to export
energy directly from a BES generating unit or generating plant to the
network.
5. Effective Dates: See Implementation Plan
.

Effective Dates
First day of the first calendar quarter beyond the date that this standard is approved by applicable
regulatory authorities, or in those jurisdictions where regulatory approval is not required, the
standard becomes effective on the first day of the first calendar quarter beyond the date this
standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
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 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.

1

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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.
6. Not used.
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
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 capability2.
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 temperature3.

2

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

3

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.

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Standard PRC-023-3 — 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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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

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Standard PRC-023-3 — Transmission Relay Loadability
within 30 calendar days of the establishment of the initial list and within 30 calendar days of
any changes to that list.
R7. Each Transmission Owner and Distribution Provider shall set their load responsive relays in
accordance with PRC-023-3, Attachment C at the terminals of the generator interconnection
Facility. [Violation Risk Factor: High] [Time Horizon: Long Term Planning].
R8. Transmission Owner and Distribution Provider shall set their load responsive relays in
accordance with PRC-023-3, Attachment C at the terminals of the generator step-up transformer.
[Violation Risk Factor: High] [Time Horizon: Long Term Planning].
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, 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 PRC-023-3, 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,

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Standard PRC-023-3 — Transmission Relay Loadability
Generator Owners, and Distribution Providers within its Planning Coordinator area within the
required timeframe.
M7. Each Transmission Owner and Distribution Provider shall have evidence (e.g., summaries of
calculations, spreadsheets, simulation reports, or setting sheets) to show that each of its
generator interconnection Facility relays is set according to one of the criteria in Attachment C.
(R7)
M8. Each Transmission Owner and Distribution Provider shall have evidence (e.g., summaries of
calculations, spreadsheets, simulation reports, or setting sheets) to show that each of its
generator step-up transformer relays is set according to one of the criteria in Attachment C.
(R8)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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, R7, and R8 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 Enforcement Authority 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

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Standard PRC-023-3 — Transmission Relay Loadability
Complaint
1.4. Additional Compliance Information
None.

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Standard PRC-023-3 — Transmission Relay Loadability

2.

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.

R2

R3

N/A

N/A

N/A

N/A

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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

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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

Severe
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.

R4

R5

R6

N/A

N/A

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

N/A

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

The Planning Coordinator used the
criteria established within
Attachment B to determine the
circuits in its Planning Coordinator
area for which applicable entities

The Planning Coordinator used the
criteria established within
Attachment B to determine the
circuits in its Planning Coordinator
area for which applicable entities

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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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.

must comply with the standard and
met parts 6.1 and 6.2, but 24
months or more 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
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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 46 days and 60 days after
list was established or updated.
(part 6.2)

Severe
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
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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

the list was established or updated.
(part 6.2)

Severe
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 the standard.

R7

R8

N/A

N/A

N/A

N/A

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N/A

The responsible entity did not set
one of its generator
interconnection Facility relays in
accordance with the criteria in
Attachment C.

N/A

The responsible entity did not set
one of its generator step-up
transformer relays in accordance
with the criteria in Attachment C.

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Standard PRC-023-3 — 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

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

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Supplemental SAR
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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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.
2.4. Protective relays applied at the terminals of generation Facilities in accordance with NERC
Reliability Standard PRC-025-1 or its successor(s).
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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 analyses4 performed by the Planning Coordinator for the one-tofive-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.
4

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

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Standard PRC-023-3 — 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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — Attachment C
The following criteria shall be used to set load-responsive relays on generator interconnection Facilities and generator-step-up transformers.
This standard does not require the responsible entity to use any of the protective functions listed in Table 1. Each responsible entity that applies
load-responsive protective relays on Facilities listed in 4.2.3 and 4.2.4, Facilities shall use one of the following Options 1-12 in Table 1, Relay
Loadability Evaluation Criteria (“Table 1”), to set each load-responsive protective relay element according to its application and relay type. The
bus voltage is based on the criteria for the various applications listed in Table 1.
Relay pickup setting criteria values related to synchronous generators are derived from the unit’s maximum gross Real Power capability, in
megawatts (MW), as reported to the Transmission Planner or other entity as specified by the Regional Reliability Organization (RRO), and the
unit’s Reactive Power capability, in megavoltampere-reactive (Mvar), is determined by calculating the MW value based on the unit’s nameplate
megavoltampere (MVA) rating at rated power factor. If different seasonal capabilities are reported, the maximum capability shall be used for the
purposes of this standard.
Relay pickup setting criteria values related to asynchronous generators (including inverter-based installations) are derived from the site’s aggregate
maximum complex power capability, in MVA, as reported to the Transmission Planner or other entity as specified by the Regional Reliability
Organization (RRO), including the Mvar output of any static or dynamic reactive power devices.
For the application case where synchronous and asynchronous generator types are combined on a generator step-up transformer or on a generator
interconnection Facility, the pickup setting criteria shall be determined by vector summing the pickup setting criteria of each generator type, and
using the bus voltage for the given synchronous generator application and relay type.
Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers
with deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest
generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU
turns ratio shall be used.
Any relay elements that are in service only during start up, when the generator is disconnected, or when other Protection System components fail
are excluded. Examples of exclusions include, but are not limited to, the following:
Load-responsive protective relay elements that are armed only when the generator is disconnected from the system, (e.g., non-directional
overcurrent elements used in conjunction with inadvertent energization schemes, and open breaker flashover schemes),
Phase fault detector relay elements employed to supervise other load-responsive phase distance elements (in order to prevent false
operation in the event of a blown secondary fuse) provided the distance element is set in accordance with the criteria outlined in the
standard,
Table 1

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Standard PRC-023-3 — Transmission Relay Loadability
The Table is structured and formatted to aid the reader with identifying an option for a given load-responsive protective relay.
The first column identifies the application (e.g., generator step-up transformers and generator interconnection Facilities). Dark blue horizontal
bars, excluding the header which repeats at the top of each page, demarcate the various applications.
The second column identifies the load-responsive protective relay (e.g., 21, 51, or 67) according to the applied application in the first column. A
light blue horizontal bar between the relay types is the demarcation between relay types for a given application. These light blue bars will contain
no text.
The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting load-responsive
protective relays according to the application and applied relay type. Another, shorter, light blue bar contains the word “OR,” and reveals to the
reader that the relay for that application has one or more options (i.e., “ways”) to determine the bus voltage and pickup setting criteria in the fourth
and fifth column, respectively. The bus voltage column and pickup setting criteria columns provide the criteria for determining an appropriate
setting.
The table is further formatted by alternately shading groups of relays within a similar application. Also, intentional buffers were added to the table
such that similar options would be paired together on a per page basis. Note that some applications may have additional pairing that might occur
on adjacent pages.

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

1a

Generator stepup transformer
connected to
synchronous
generators

Phase distance
relay (21) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 7

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

1b

OR

1c

The same application continues on the next page with a different relay type

5

Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with
deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When
the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU turns ratio shall be used.

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

2a

Generator stepup transformer
connected to
synchronous
generators

Phase time
overcurrent relay
(51) – installed on
generator-side of
GSU
If the relay is
installed on the
high-side of GSU
use Option 8

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

2b

OR

2c

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

3a

Generator stepup transformer
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system– installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 9

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

3b

OR

3c

A different application starts on the next page

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Generator stepup transformer
connected to
asynchronous
generators only
(including
inverter-based
installations)

Relay Type
Phase distance
relay (21) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 10

Phase time
overcurrent relay
(51) – installed on
generator-side of
GSU
If the relay is
installed on the
high-side of GSU
use Option 11

Option

Bus Voltage5

Pickup Setting Criteria

4

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated impedance
derived from 130% of the maximum aggregate nameplate MVA
output at rated power factor (including the Mvar output of any static or
dynamic reactive power devices)

5

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer
for overcurrent relays installed on the
low-side

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 12

6

Bus Voltage5

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Pickup Setting Criteria

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

A different application begins below

7a

Generator
interconnection
Facilities
connected to
synchronous
generators

Phase distance
relay (21) –
directional toward
the Transmission
system

0.85 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

7b

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

8a

Phase time
overcurrent relay
(51)

Generator
interconnection
Facilities
connected to
synchronous
generators

Bus Voltage5

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

8b

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

9a
Generator
interconnection
Facilities
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system

Bus Voltage5

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

9b

A different application starts on the next page

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type
Phase distance
relay (21) –
directional toward
the Transmission
system

Generator
interconnection
Facilities
connected to
asynchronous
generators only
(including
inverter-based
installations)

Phase time
overcurrent relay
(51)

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system

Option

Bus Voltage5

Pickup Setting Criteria

10

1.0 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated impedance
derived from 130% of the maximum aggregate nameplate MVA
output at rated power factor (including the Mvar output of any static or
dynamic reactive power devices)

11

1.0 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

12

1.0 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

End of Table 1

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Implementation Plan

PRC-023-3 – Transmission Relay Loadability
Project 2010-13.2 Phase II Relay Loadability
Requested Approvals



PRC‐023‐3 – Transmission Relay Loadability 

Requested Retirements



PRC‐023‐2 – Transmission Relay Loadability 

Prerequisite Approvals



PRC‐025‐1 – Generator Relay Loadability* 
*A supplemental SAR was approved by the Standards Committee at their January 16‐17, 2013 meeting to 
authorize the drafting team to make changes to PRC‐023‐2 to comport with the proposed draft PRC‐025‐
1 – Generator Relay Loadability in order to establish a bright line between the applicability of load‐
responsive protective relays in the current transmission and the proposed generator relay loadability 
standards. 

Revisions to Defined Terms in the NERC Glossary



None 

Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is 
no bright line to clearly distinguish which load‐responsive protective relays pertain to the existing PRC‐023‐2 – 
Transmission Relay Loadability standard, effective in the United States on July 1, 2012, and the proposed PRC‐
025‐1 – Generator Relay Loadability standard. To resolve this concern, the drafting team proposed to modify 
the applicability section of PRC‐023‐2. The standard drafting team clarified, for each functional entity, the 
applicability of PRC‐023‐2 by tying applicability to the terminal the load‐responsive protective relay is 
connected to within the Transmission system. 
Requirements R1 though R6 continue to apply to the Generator Owner to avoid a potential gap in situations 
where this entity owns load‐responsive protective relays subject to transmission line relay loadability (PRC‐
023). These situations could be the result of a current configuration or future changes or additions in 
transmission configurations.  

The proposed PRC‐023‐3 standard also includes two new Requirements, R7 and R8 to address load‐responsive 
protective relay loadability in cases where the Distribution Provider or Transmission Owner owns generator 
interconnection Facilities or generator step‐up (GSU) transformers. The implementation time for 
Requirements R7 and R8 comports with the periods established in the proposed PRC‐025‐1 Implementation 
Plan. 
General Considerations

It is expected that the implementation period for PRC‐023‐2 will have been achieved, in part, by the time PRC‐
023‐3 is adopted by the NERC Board of Trustees and by the time of other approvals by applicable 
governmental authorities. The proposed PRC‐023‐3 Implementation Plan now reflects specific milestone dates 
that are known, time periods consistent with PRC‐023‐2, and an implementation period for new Requirements 
R7 and R8.  
Applicable Entities



Distribution Provider 



Generator Owner 



Planning Coordinator 



Transmission Owner 

Effective Date
New Standard

PRC‐023‐3 

First day of the first calendar quarter beyond the date that this standard is 
approved by applicable regulatory authorities, or in those jurisdictions where 
regulatory approval is not required, the standard becomes effective on the 
first day of the first calendar quarter beyond the date this standard is 
approved by the NERC Board of Trustees, or as otherwise made effective 
pursuant to the laws applicable to such ERO governmental authorities. 

Standards for Retirement

PRC‐023‐2 

Midnight of the day immediately prior to the Effective Date of PRC‐023‐3 – 
Transmission Relay Loadability in the particular jurisdiction in which the new 
standard is becoming effective. 

Implementation Plan for Definitions

No definitions are proposed as a part of this standard. 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

2

Implementation Plan for PRC-023-3, Requirements R1 through R6

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to 
this standard shall be 100% compliant on the following dates: 
Implementation 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. 


R1 



For supervisory elements as 
described in PRC‐023‐3 ‐ Attachment 
A, Section 1.6 

For switch‐on‐to‐fault schemes as 
described in PRC‐023‐3 ‐ Attachment 
A, Section 1.3 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

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, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

The later of July 1, 
2014 or first day of the 
first calendar quarter 
after applicable 
regulatory approvals 

First day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

First day of the first 
calendar quarter after 
applicable regulatory 
approvals 

First day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

3

Implementation Date 
Requirement 

R1 
(continued) 

R2 and R3 

Applicability 

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

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 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

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 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 

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 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 

First day of the first 
calendar quarter after 
applicable regulatory 
approvals 

First day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

4

Implementation Date 
Requirement 

R2 and R3 
continued 

R4 

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 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 

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 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 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 Board of 
First day of the first 
Trustees adoption, or 
as otherwise made 
calendar quarter six 
months after applicable  effective pursuant to 
the laws applicable to 
regulatory approvals 
such ERO 
governmental 
authorities 

Applicability 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

5

Implementation 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 day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

R5 

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

R6 

First day of the first 
calendar quarter after 
Each Planning Coordinator shall conduct 
Board of Trustees 
an assessment by applying the criteria in  Later of January 1, 
adoption, or as 
Attachment B to determine the circuits in  2014 or the first day of 
otherwise made 
its Planning Coordinator area for which 
the first calendar 
effective pursuant to 
Transmission Owners, Generator Owner,  quarter after applicable 
the laws applicable to 
and Distribution Providers must comply 
regulatory approvals 
such ERO 
with Requirements R1 through R5 
governmental 
authorities 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

6

Implementation Plan for PRC-023-3, Requirements R7 and R8

Load‐responsive protective relays subject to the standard 
Each Transmission Owner and Distribution Provider that owns load‐responsive protective relays applicable to 
this standard shall be 100% compliant on the following dates: 
Implementation Date 
Requirement 

Applicability 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Where determined by the 
Distribution Provider that 
Transmission Owner and 
replacement or removal is not 
Distribution Provider that 
necessary, the first day 48 
replacement or removal is not 
months after Board of Trustees 
necessary, the first day 48 
adoption, or as otherwise 
months after applicable 
made effective pursuant to the 
regulatory approvals 
laws applicable to such ERO 
governmental authorities 

R7 

Each Transmission Owner 
and Distribution Provider 
shall set their load 
responsive relays in 
accordance with PRC‐023‐
3, Attachment C at the 
terminals of the generator 
interconnection Facility. 
Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after applicable 
regulatory approvals 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after Board of Trustees 
adoption, or as otherwise 
made effective pursuant to the 
laws applicable to such ERO 
governmental authorities 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

7

Implementation Date 
Requirement 

R8 

Applicability 

Transmission Owner and 
Distribution Provider shall 
set their load responsive 
relays in accordance with 
PRC‐023‐3, Attachment C 
at the terminals of the 
generator step‐up 
transformer. 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Where determined by the 
Distribution Provider that 
Transmission Owner and 
replacement or removal is not 
Distribution Provider that 
necessary, the first day 48 
replacement or removal is not 
months after Board of Trustees 
necessary, the first day 48 
adoption, or as otherwise 
months after applicable 
made effective pursuant to the 
regulatory approvals 
laws applicable to such ERO 
governmental authorities 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after applicable 
regulatory approvals 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after Board of Trustees 
adoption, or as otherwise 
made effective pursuant to the 
laws applicable to such ERO 
governmental authorities 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

8

Load‐responsive protective relays which become applicable to the standard 
Each Transmission Owner and Distribution Provider that owns load‐responsive protective relays that become 
applicable to this standard, not because of the actions of the Transmission Owner and Distribution Provider 
including, but not limited to changes in NERC Registration Criteria, Bulk Electric System (BES) definition, or any 
other non‐Generator Owner action, shall be 100% compliant on the following dates: 
Implementation Date 
Requirement 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Applicability 

R7 

Each Transmission Owner 
and Distribution Provider 
shall set their load 
responsive relays in 
accordance with PRC‐023‐
3, Attachment C at the 
terminals of the generator 
interconnection Facility. 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

9

Implementation Date 
Requirement 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Applicability 

R8 

Transmission Owner and 
Distribution Provider shall 
set their load responsive 
relays in accordance with 
PRC‐023‐3, Attachment C 
at the terminals of the 
generator step‐up 
transformer. 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

10

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is 
implemented. If the drafting team is recommending revisions, those changes are identified in bold blue with underlining for additions and 
for deletions in bold red with a strikeout. 

Already Approved Standard 
PRC‐023‐2 
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 

Proposed Replacement 
PRC‐023‐3 
4.1.Functional Entity 
4.1.1  Transmission Owners with load‐responsive phase protection 
systems as described in PRC‐023‐2 3 ‐ Attachment A, applied at the 
terminals of the to circuits defined in 4.2.1, 4.2.3, or 4.2.4 (Circuits 
Subject to Requirements R1 – R5, R7, and R8). 
4.1.2  Generator Owners with load‐responsive phase protection 
systems as described in PRC‐023‐3 ‐ Attachment A, applied at the 
terminals of the 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 3 ‐ Attachment A, applied at the 
terminals of the to circuits defined in 4.2.1, 4.2.3, or 4.2.4 (Circuits 
Subject to Requirements R1 – R5, R7, and R8), provided those circuits 
have bi‐directional flow capabilities. 
4.1.4  Planning Coordinators 

Notes: The change in the proposed PRC‐023‐3 Applicability creates a bright line between those load‐responsive protective relays that are 
applicable to PRC‐023‐3 – Transmission Relay Loadability and the proposed PRC‐025‐1 – Generator Relay Loadability. This is evident by the minor 
changes to the Applicability text to distinguish the applicability of the relays by which “terminal” the load‐responsive protective relay is 
connected to within the Transmission system. 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

11

Already Approved Standard 
PRC‐023‐2 
None. 

Proposed Replacement 
PRC‐023‐3 
New applicability 
4.2 
Circuits 
4.2.3  Circuits Subject to Requirement R7 
4.2.3.1 Transmission lines that are used solely to export energy 
directly from a BES generating unit or generating plant to the 
network. 
4.2.4  Circuits Subject to Requirement R8 
4.2.2.2 Transformers with low voltage terminals connected 
below 200 kV, including generator step‐up transformers, that 
are used solely to export energy directly from a BES generating 
unit or generating plant to the network. 

Notes: The above two new applicability items for circuits subject to the standard were added to address to situations where the Distribution 
Provider or Transmission Owner own either generator interconnection Facilities or generator step‐up (GSU) transformers, respectively.  
PRC‐023‐2 
R1, Criterion 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. 

PRC‐023‐3 
New Requirement 
R7.  Each Transmission Owner and Distribution Provider shall set 
their load responsive relays in accordance with PRC‐023‐3, Attachment 
C at the terminals of the generator interconnection Facility. [Violation 
Risk Factor: High] [Time Horizon: Long Term Planning]. 

Notes: This new requirement is included to address a gap concerning generator step‐up (GSU) transformers where the Transmission Owner or 
Distribution Provider has applied load‐responsive protective relays. Referencing the proposed Applicability section 4.2.4, Circuits Subject to 
Requirement R8, this requirement closes the gap for those transformers that have low voltage terminals connected below 200 kV. Currently, only 
those Transmission system transformers with low voltage terminals connected at 200 kV and above are applicable to the Transmission Owner or 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

12

Already Approved Standard 

Proposed Replacement 

Distribution Provider or transformers with low voltage terminals under 200 kV if the Planning Coordinator determines (in accordance with 
requirement R6) that they should be subject to PRC‐023‐3. This is identified by in the proposed Applicability 4.2.1.4. This requirement eliminates 
the gap between the proposed PRC‐023‐3 and PRC‐025‐1 so that generator step‐up (GSU) transformers (i.e., where the Transmission system 
transformer is the transmission line termination – Criterion 10) apply to the Transmission Owner or Distribution Provider in the proposed PRC‐
023‐3 in the same manner as the Generator Owner in the proposed PRC‐025‐1. 
Circuits subject to R8 are primarily GSU transformers and also include “aggregated generator transformers” – those connecting wind farms, and 
photovoltaic sites. 
PRC‐023‐2 
None. 

PRC‐023‐3 
New Requirement 
R8.  Transmission Owner and Distribution Provider shall set their 
load responsive relays in accordance with PRC‐023‐3, Attachment C at 
the terminals of the generator step‐up transformer. [Violation Risk 
Factor: High] [Time Horizon: Long Term Planning]. 

Notes: The above new Requirement R7 addresses a gap between the proposed PRC‐023‐3 and PRC‐025‐1 standards. This requirement applies to 
the condition where the Transmission Owner or Distribution Provider apply load‐responsive protective relays on a generator interconnection 
Facility(ies). Rather than add Transmission Owner and Distribution Provider to the proposed PRC‐025‐1, it was equally and efficient to include the 
same loadability criteria as the proposed PRC‐025‐1 in the proposed PRC‐023‐3 standard. Requirement R7 proposes to replace the current PRC‐
023‐2, Requirement R1, Criterion 6 with a new requirement. Criterion 6 for setting the load‐responsive protective relays so they do not operate 
at or below 230% now has additional flexibility in setting such relays according to Attachment C which is referenced in this new Requirement, R7. 
The 230% criterion comports with the loadability criteria found in the proposed PRC‐023‐3 Attachment C. The Transmission Owner and 
Distribution Provider in the proposed PRC‐023‐3 will have the same options for setting its load‐responsive protective relays when applied on 
generator interconnection Facility(ies) as the Generator Owner in the proposed PRC‐025‐1. 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (Draft 2: April 24, 2013) 

13

Implementation Plan
Project 2010-13.2 - Relay Loadability: Generator
PRC-023-3 – Transmission Relay Loadability
Project 2010-13.2 Phase II Relay Loadability
Requested Approvals



PRC‐023‐3 – Transmission Relay Loadability 

Requested Retirements



PRC‐023‐2 – Transmission Relay Loadability 

Prerequisite Approvals


PRC‐025‐1 – Generator Relay Loadability* 
*A supplemental SAR was approved by the Standards Committee at their January 16‐17, 2013 meeting 
to authorize the drafting team to make changes to PRC‐023‐2 to comport with the proposed draft PRC‐
025‐1 – Generator Relay Loadability and in order to establish a bright line between the applicability of 
load‐responsive protective relays in the current transmission and the proposed generator relay 
loadability standards. 

Revisions to Defined Terms in the NERC Glossary



None 

Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is 
no bright line to clearly distinguish which load‐responsive protective relays pertain to theabout the potential 
for overlap between existing PRC‐023‐2 – Transmission Relay Loadability standard, effective in the United 
States on July 1, 2012, and the proposed PRC‐025‐1 – Generator Relay Loadability standards.  The concern is 
that there was no bright line to clearly distinguish which load‐responsive protective relays pertain to each 
standard. To resolve this concern, the  The drafting team researched the issue and proposed to modify the 
applicability section of PRC‐023‐2. The standard drafting team clarified, for  to clarify the each functional 
entity, theentity’s applicability of PRC‐023‐2 by tying applicability to thewith respect to which terminal the 
load‐responsive protective relay is connected to within the Transmission system. 
Requirements R1 though R6 continue to apply to the Generator Owner to avoid a potential gap in situations 
where this entity owns load‐responsive protective relays subject to transmission line relay loadability (PRC‐

023). These situations could be the result of a current configuration or future changes or additions in 
transmission configurations.  
The proposed PRC‐023‐3 standard also includes two new Requirements, R7 and R8 to address load‐responsive 
protective relay loadability in cases where the Distribution Provider or Transmission Owner owns generator 
interconnection Facilities or generator step‐up (GSU) transformers. The implementation time for 
Requirements R7 and R8 comports with the periods established in the proposed PRC‐025‐1 Implementation 
Plan. 
General Considerations

ItThe Implementation Plan period reflects consideration that a specific period is not required because no new 
entity or facilities are subject to compliance. Also, it is expected that the implementation plan and period for 
PRC‐023‐2 will have been achieved, and that it will not need to be considered in part, by the time PRC‐023‐3 is 
adopted by the NERC Board of Trustees and by the time of other approvals by applicable governmental 
authorities. The proposed PRC‐023‐3 Implementation Plan now reflects specific milestone dates that are 
known, time periods consistentconjunction with PRC‐023‐2, and an implementation period for new 
Requirements R7 and R8. this revision. 
Applicable Entities



Distribution Provider 



Generator Owner 



Planning Coordinator 



Transmission Owner 

Effective Date
New Standard

PRC‐023‐3 

First day of the first calendar quarter beyond the date that this standard is 
approved by applicable regulatory authorities, or in those jurisdictions where 
regulatory approval is not required, the standard becomes effective on the 
first day of the first calendar quarter beyond the date this standard is 
approved by the NERC Board of Trustees, or as otherwise made effective 
pursuant to the laws applicable to such ERO governmental authorities. 

Standards for Retirement

PRC‐023‐2 

Midnight of the day immediately prior to the Effective Date of PRC‐023‐32 – 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

2

Transmission Relay Loadability in the particular jurisdiction in which the new 
standard is becoming effective. 
Implementation Plan for Definitions

No definitions are proposed as a part of this standard. 
Implementation Plan for PRC-023-3, Requirements R1 through R6All requirements

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to 
this standard shall be 100% compliant on the following dates:effective date of the standard according to the 
jurisdiction. 
Implementation 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. 

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, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

The later of July 1, 
2014 or first day of the 
first calendar quarter 
after applicable 
regulatory approvals 

First day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

R1 



For supervisory elements as 
described in PRC‐023‐3 ‐ Attachment 
A, Section 1.6 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

3

Implementation Date 
Requirement 

Applicability 



R1 
(continued) 

For switch‐on‐to‐fault schemes as 
described in PRC‐023‐3 ‐ Attachment 
A, Section 1.3 

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

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 day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

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 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 

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 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 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

4

Implementation Date 
Requirement 

R2 and R3 

R2 and R3 
continued 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

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 

First day of the first 
calendar quarter after 
applicable regulatory 
approvals 

First day of the first 
calendar quarter after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

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 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 

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 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 

Applicability 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

5

Implementation Date 
Requirement 

Applicability 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

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 Board of 
First day of the first 
Trustees adoption, or 
calendar quarter six 
as otherwise made 
months after applicable  effective pursuant to 
regulatory approvals 
the laws applicable to 
such ERO 
governmental 
authorities 

R5 

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 after 
Board of Trustees 
adoption, or as 
otherwise made 
effective pursuant to 
the laws applicable to 
such ERO 
governmental 
authorities 

R6 

First day of the first 
calendar quarter after 
Each Planning Coordinator shall conduct 
Board of Trustees 
an assessment by applying the criteria in  Later of January 1, 
adoption, or as 
Attachment B to determine the circuits in  2014 or the first day of 
otherwise made 
its Planning Coordinator area for which 
the first calendar 
effective pursuant to 
Transmission Owners, Generator Owner,  quarter after applicable 
the laws applicable to 
and Distribution Providers must comply 
regulatory approvals 
such ERO 
with Requirements R1 through R5 
governmental 
authorities 

R4 

First day of the first 
calendar quarter after 
applicable regulatory 
approvals 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

6

Implementation Plan for PRC-023-3, Requirements R7 and R8

Load‐responsive protective relays subject to the standard 
Each Transmission Owner and Distribution Provider that owns load‐responsive protective relays applicable to 
this standard shall be 100% compliant on the following dates: 
Implementation Date 
Requirement 

Applicability 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Where determined by the 
Distribution Provider that 
Transmission Owner and 
replacement or removal is not 
Distribution Provider that 
necessary, the first day 48 
replacement or removal is not 
months after Board of Trustees 
necessary, the first day 48 
adoption, or as otherwise 
months after applicable 
made effective pursuant to the 
regulatory approvals 
laws applicable to such ERO 
governmental authorities 

R7 

Each Transmission Owner 
and Distribution Provider 
shall set their load 
responsive relays in 
accordance with PRC‐023‐
3, Attachment C at the 
terminals of the generator 
interconnection Facility. 
Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after applicable 
regulatory approvals 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after Board of Trustees 
adoption, or as otherwise 
made effective pursuant to the 
laws applicable to such ERO 
governmental authorities 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

7

Implementation Date 
Requirement 

R8 

Applicability 

Transmission Owner and 
Distribution Provider shall 
set their load responsive 
relays in accordance with 
PRC‐023‐3, Attachment C 
at the terminals of the 
generator step‐up 
transformer. 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Where determined by the 
Distribution Provider that 
Transmission Owner and 
replacement or removal is not 
Distribution Provider that 
necessary, the first day 48 
replacement or removal is not 
months after Board of Trustees 
necessary, the first day 48 
adoption, or as otherwise 
months after applicable 
made effective pursuant to the 
regulatory approvals 
laws applicable to such ERO 
governmental authorities 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after applicable 
regulatory approvals 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months after Board of Trustees 
adoption, or as otherwise 
made effective pursuant to the 
laws applicable to such ERO 
governmental authorities 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

8

Load‐responsive protective relays which become applicable to the standard 
Each Transmission Owner and Distribution Provider that owns load‐responsive protective relays that become 
applicable to this standard, not because of the actions of the Transmission Owner and Distribution Provider 
including, but not limited to changes in NERC Registration Criteria, Bulk Electric System (BES) definition, or any 
other non‐Generator Owner action, shall be 100% compliant on the following dates: 
Implementation Date 
Requirement 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Applicability 

R7 

Each Transmission Owner 
and Distribution Provider 
shall set their load 
responsive relays in 
accordance with PRC‐023‐
3, Attachment C at the 
terminals of the generator 
interconnection Facility. 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

9

Implementation Date 
Requirement 

Jurisdictions where 
Regulatory Approval is 
Required 

Jurisdictions where No 
Regulatory Approval is 
Required 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is not 
necessary, the first day 48 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Applicability 

R8 

Transmission Owner and 
Distribution Provider shall 
set their load responsive 
relays in accordance with 
PRC‐023‐3, Attachment C 
at the terminals of the 
generator step‐up 
transformer. 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Where determined by the 
Transmission Owner and 
Distribution Provider that 
replacement or removal is 
necessary, the first day 72 
months beyond the date the 
load‐responsive protective 
relays become applicable to 
the standard 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

10

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is 
implemented.  If the drafting team is recommending revisions, those changes are identified in boldthe retirement or revision of a 
requirement, that text is blue with underlining for additions and for deletions in bold red with a strikeout. 

Already Approved Standard 
PRC‐023‐2 
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 

Proposed Replacement Requirement(s) 
PRC‐023‐3 
4.1.Functional Entity 
4.1.1  Transmission Owners with load‐responsive phase protection 
systems as described in PRC‐023‐2 3 ‐ Attachment A, applied at the 
terminals of the to circuits defined in 4.2.1, 4.2.3, or 4.2.4 (Circuits 
Subject to Requirements R1 – R5, R7, and R8). 
4.1.2  Generator Owners with load‐responsive phase protection 
systems as described in PRC‐023‐32 ‐ Attachment A, applied at the 
terminals of the 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 3 ‐ Attachment A, applied at the 
terminals of the to circuits defined in 4.2.1, 4.2.3, or 4.2.4 (Circuits 
Subject to Requirements R1 – R5, R7, and R8), provided those circuits 
have bi‐directional flow capabilities. 
4.1.4  Planning Coordinators 

Notes:  The change in the proposed PRC‐023‐3 Applicabilityapplicability creates a bright line between those load‐responsive protective relays 
that are applicable to PRC‐023‐3 – Transmission Relay Loadability and the proposed PRC‐025‐1 – Generator Relay Loadability.  This is evident by 
the minor changes to the Aapplicability text to distinguish the applicability of the relays by which “terminal” the load‐responsive protective relay 
is connected to within the Transmission system. 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

11

Already Approved Standard 
PRC‐023‐2 
None. 

Proposed Replacement Requirement(s) 
PRC‐023‐3 
New applicability 
4.2 
Circuits 
4.2.3  Circuits Subject to Requirement R7 
4.2.3.1 Transmission lines that are used solely to export energy 
directly from a BES generating unit or generating plant to the 
network. 
4.2.4  Circuits Subject to Requirement R8 
4.2.2.2 Transformers with low voltage terminals connected 
below 200 kV, including generator step‐up transformers, that 
are used solely to export energy directly from a BES generating 
unit or generating plant to the network. 

Notes: The above two new applicability items for circuits subject to the standard were added to address to situations where the Distribution 
Provider or Transmission Owner own either generator interconnection Facilities or generator step‐up (GSU) transformers, respectively.  
PRC‐023‐2 
R1, Criterion 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. 

PRC‐023‐3 
New Requirement 
R7.  Each Transmission Owner and Distribution Provider shall set 
their load responsive relays in accordance with PRC‐023‐3, Attachment 
C at the terminals of the generator interconnection Facility. [Violation 
Risk Factor: High] [Time Horizon: Long Term Planning]. 

Notes: This new requirement is included to address a gap concerning generator step‐up (GSU) transformers where the Transmission Owner or 
Distribution Provider has applied load‐responsive protective relays. Referencing the proposed Applicability section 4.2.4, Circuits Subject to 
Requirement R8, this requirement closes the gap for those transformers that have low voltage terminals connected below 200 kV. Currently, only 
those Transmission system transformers with low voltage terminals connected at 200 kV and above are applicable to the Transmission Owner or 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

12

Already Approved Standard 

Proposed Replacement Requirement(s) 

Distribution Provider or transformers with low voltage terminals under 200 kV if the Planning Coordinator determines (in accordance with 
requirement R6) that they should be subject to PRC‐023‐3. This is identified by in the proposed Applicability 4.2.1.4. This requirement eliminates 
the gap between the proposed PRC‐023‐3 and PRC‐025‐1 so that generator step‐up (GSU) transformers (i.e., where the Transmission system 
transformer is the transmission line termination – Criterion 10) apply to the Transmission Owner or Distribution Provider in the proposed PRC‐
023‐3 in the same manner as the Generator Owner in the proposed PRC‐025‐1. 
Circuits subject to R8 are primarily GSU transformers and also include “aggregated generator transformers” – those connecting wind farms, and 
photovoltaic sites. 
PRC‐023‐2 
None. 

PRC‐023‐3 
New Requirement 
R8.  Transmission Owner and Distribution Provider shall set their 
load responsive relays in accordance with PRC‐023‐3, Attachment C at 
the terminals of the generator step‐up transformer. [Violation Risk 
Factor: High] [Time Horizon: Long Term Planning]. 

Notes: The above new Requirement R7 addresses a gap between the proposed PRC‐023‐3 and PRC‐025‐1 standards. This requirement applies to 
the condition where the Transmission Owner or Distribution Provider apply load‐responsive protective relays on a generator interconnection 
Facility(ies). Rather than add Transmission Owner and Distribution Provider to the proposed PRC‐025‐1, it was equally and efficient to include the 
same loadability criteria as the proposed PRC‐025‐1 in the proposed PRC‐023‐3 standard. Requirement R7 proposes to replace the current PRC‐
023‐2, Requirement R1, Criterion 6 with a new requirement. Criterion 6 for setting the load‐responsive protective relays so they do not operate 
at or below 230% now has additional flexibility in setting such relays according to Attachment C which is referenced in this new Requirement, R7. 
The 230% criterion comports with the loadability criteria found in the proposed PRC‐023‐3 Attachment C. The Transmission Owner and 
Distribution Provider in the proposed PRC‐023‐3 will have the same options for setting its load‐responsive protective relays when applied on 
generator interconnection Facility(ies) as the Generator Owner in the proposed PRC‐025‐1. 

Implementation Plan (PRC‐023‐3) 
Project 2010‐13.2 – Phase II‐ Relay Loadability (:  Generator (SAR Draft 2: April 241: January 17, 2013) 

13

Unofficial Comment Form

Project 2010-13.2 Phase II Relay Loadability
(PRC-025-1 and PRC-023-2)

Please DO NOT use this form for submitting comments. Please use the electronic form [insert
hyperlink to electronic form] located at the link below to submit comments on the Standard.
The electronic comment form must be completed by May 24, 2013. If you have questions
please contact Scott Barfield-McGinnis at [email protected] or by telephone at (404) 4469689.
http://www.nerc.com/filez/standards/Project_2010-13.2_Summary_Table.html
Background Information

This posting is soliciting formal comments in a 30-day formal comment period.
The Standard Authorization Request (SAR) for this project was initiated on August 5, 2010 and
approved by the Standards Committee (SC) on August 12, 2010. It established the scope of
work for Project 2010-13.2 for what is the second phase of Order 733, Transmission Relay
Loadability Reliability Standard. 1 Phase I resulted in the NERC Reliability Standard PRC-023-1
and Phase II concerning this project specifically addresses protecting the generator, generator
step-up (GSU) transformer, and unit auxiliary transformers (UAT) in the proposed new
standard, PRC-025-1. The SC moved this project into active development on March 8, 2012.
During analysis of many of the major disturbances in the last 25 years on the North American
interconnected power system, generators have been found to have tripped for conditions that
did not apparently pose a direct risk to those generators and associated equipment within the
time period where the tripping occurred. This unnecessary tripping has often been evaluated to
have extended the scope and/or duration of that disturbance. This was noted, in detail, to be a
serious issue in the August 2003 “blackout’ in the northeastern North American continent.
During the recoverable phase of a disturbance, the disturbance may exhibit a “voltage
disturbance” behavior pattern, where system voltage is widely depressed. In order to support
the system during this phase of a disturbance, this standard establishes criteria for setting loadresponsive relays such that individual generators may provide Reactive Power within their
dynamic capability during transient time periods to help the system recover from that voltage
disturbance. The premature or unnecessary tripping of generators resulting in the removal of
dynamic Reactive Power exacerbates the severity of the voltage disturbance, and as a result

1

Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010), Paragraphs 104, 105, 106, and 108.

changes the character of the system disturbance. In addition, the loss of Real Power could
initiate or exacerbate a frequency disturbance.
The Standard Drafting Team has developed draft three of the standard to provide requirements
that address these concerns, and is presenting this draft to industry for a formal comment
period to get industry comments to aid in further development.
Summary of changes

The generator relay loadability standard drafting team (“SDT”) has revised the proposed the
draft of PRC-023-3 – Transmission Relay Loadability based on stakeholder comments received
during the Standard Authorization Request (SAR) 45-day formal posting of the SAR which
included a redline to the PRC-023-2 standard. The SAR was not modified by the standard
drafting team. Contemporaneously with the SAR posting, the SDT has revised the proposed
draft of PRC-025-1 – Generator Relay Loadability during its 45-day formal comment posting of
the standard and initial ballot which received 54.65% stakeholder approval. The following
narrative is a summary of the significant improvements made to the above standards.
Standard (PRC-023-3)

•

•

Applicability
o The phase “at the terminal of the” was inserted in for each applicable entity of the
standard to create a bright light between the proposed PRC-023-3 and PRC-025-1
standards
o References to the two new Requirements (R7 and R8) was inserted for the applicable
Distribution Provider and Transmission Owner
o References to the two new Applicability for Circuits (4.2.3 and 4.24) were inserted for
the applicable Distribution Provider and Transmission Owner
o Applicability 4.2.3 – Circuits Subject to Requirement R7 was added to create a bright
line between the proposed PRC-023-3 and PRC-025-1 standards for the Distribution
Provider and Transmission Owner regarding generator interconnection Facilities
o Applicability 4.2.4 – Circuits Subject to Requirement R8 was added to create a bright
line between the proposed PRC-023-3 and PRC-025-1 standards for the Distribution
Provider and Transmission Owner regarding generator step-up (GSU) transformers
Requirements
o Requirement R1, Criterion 6 was removed and replaced by two new proposed
Requirements R7 and R8
o New Requirement R7 applicable to the Distribution Provider and Transmission Owner
regarding generator interconnection Facilities to create a bright line between the
proposed PRC-023-3 and PRC-025-1 in applying settings to load-responsive protective
relay for loadability
o New Requirement R8 applicable to the Distribution Provider and Transmission Owner
regarding generator step-up (GSU) transformer to create a bright line between the

Unofficial Comment Form
Project 2010-13.2 –Phase II Relay Loadability (Draft 3: PRC-025-1) April 25, 2013

2

proposed PRC-023-3 and PRC-025-1 in applying settings to load-responsive protective
relay for loadability
•

Measures
o New Measure M7 was inserted to correspond to the new Requirement R7
o New Measure M8 was inserted to correspond to the new Requirement R8

•

Compliance
o The Compliance Monitoring Responsibility section text was updated to current NERC
Reliability Standards language
o Requirements R7 and R8 were added to the Data Retention section
o The reference to “Compliance Monitor” was updated to the more correct term,
“Compliance Enforcement Authority”

•

Violation Severity Levels
o New VSL was inserted for Requirement R7
o New VSL was inserted for Requirement R8
o Removed references to Requirement R1, Criterion 6 because it is no longer used

•

Attachment A
o Revised criterion 2.4 to address relays applied at the terminals of generation Facilities
in accordance with NERC Reliability Standard PRC-025-1 for the Planning Coordinator
pursuant to Requirement R6

•

Attachment C
o Inserted new attachment to address relay loadability described in Requirements R7
and R8
o Includes Table 1, Relay Loadability Evaluation Criteria which is the same as the criteria
proposed in PRC-025-1 for generator interconnection Facilities and generator step-up
(GSU) transformers

Implementation Plan (PRC-023-3)

•
•

Updated to reflect known milestone dates based on the approvals of the current version
two
Added the implementation period for the two new Requirements (R7 and R8) to align
with the same implementation period proposed in PRC-025-1

VRF/VSL Justifications (PRC-023-3)

•

Provided justification for VRF/VSL for the two new Requirements R7 and R8

Unofficial Comment Form
Project 2010-13.2 –Phase II Relay Loadability (Draft 3: PRC-025-1) April 25, 2013

3

Standard (PRC-025-1)

•
•
•
•
•
•
•

Purpose
o Revised to remove the first occurrence of “generator”
o Other minor revisions to provide clarity in the scope of the standard
Applicability
o Inserted section 3.2.5 to provide applicability to Facilities that address Elements
utilized in the aggregation of dispersed power producing resources.
Requirements
o No change
Measures
o No change
Compliance
o No change
Violation Severity Levels
o No change
Attachment 1
o General text revisions
o Included language to note that the standard does not require the use of any of the
protective functions list in Table 1, Relay Loadability Evaluation Criteria
o Removed the Planning Coordinator and inserted the Regional Reliability Organization
to comport with the anticipated retirement of MOD-024-1 and MOD-025-1 and the
approval of MOD-025-2 in both the text and Table 1
o Inserted language to address situations where the Generator Owner may combine
both asynchronous and synchronous generators on a generator interconnection
Facility to provide direction on the evaluation of relay loadability
o Update the references to no-load tap changes (NLTC) and on-load tap changers (OLTC)
to the generally accepted use of the IEEE terms, deenergized tap changers (DETC) and
load tap changers (LTC)
o Added an exception to the standard for Protection Systems that detect generator
overloads
o Added an exception to the standard for Protection Systems that detect transformer
overloads
o Made minor editorial edits to Table 1 text for clarity such as replacing “connected to”
with “aggregate” for consistency with other uses
o Made minor editorial edits to remove hyphens and inserting the word “connected”
(e.g., Generator step-up transformer [connected] to asynchronous generators)
o For the application of generator interconnection Facility, reduced the Reactive Power
output calculation from 150% to 120% for consistency with the previous PRC-023-2,
Requirement R1, Criterion 6

Unofficial Comment Form
Project 2010-13.2 –Phase II Relay Loadability (Draft 3: PRC-025-1) April 25, 2013

4

Implementation Plan (PRC-025-1)

•
•

•

Minor editorial edits for clarity
Updated the implementation information to mimic the table provided in the current PRC023-2 and proposed PRC-023-3 to delineate the implementation for jurisdictions where
regulatory approval is required and in jurisdictions where no regulatory approval is
necessary
Inserted language concerning who the Real and Reactive Power is reported to by the
Generator Owner to allow a transition from reporting to the Regional Reliability
Organization to the Transmission Planner rather than having the Planning Coordinator as
identified in the previous posting of the PRC-025-1 standard

VRF/VSL Justifications (PRC-023-3)

Inserted references to the two new Requirements R7 and R8 proposed in PRC-023-3 to support
reasoning for assigning of a VRF/VSL

Unofficial Comment Form
Project 2010-13.2 –Phase II Relay Loadability (Draft 3: PRC-025-1) April 25, 2013

5

*Please use the electronic comment form to submit your final comments to NERC.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Please note that the official comment form does not retain formatting (even if it appears to
transfer formatting when you copy from the unofficial Word version of the form into the official
electronic comment form). If you enter extra carriage returns, bullets, automated numbering,
symbols, bolding, italics, or any other formatting, that formatting will not be retained when you
submit your comments.
•
•
•
•
•

Separate discrete comments by idea, e.g., preface with (1), (2), etc.
Use brackets [] to call attention to suggested inserted or deleted text.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
Do not use formatting such as extra carriage returns, bullets, automated numbering,
bolding, or italics.
Please do not repeat other entity’s comments. Select the appropriate item to support
another entity’s comments. An opportunity to enter additional or exception comments
will be available.

1. Do the changes to the proposed PRC-023-2 and PRC-025-1 (listed above) provide a bright
line between the two standards? If not, provide specific suggestions to improve or clarify
the performance between the standards.
Yes
No
Comments:
2. Does the Table 1: Relay Loadability Evaluation Criteria in both PRC-023-3 (Attachment C)
and PRC-025-1 (Attachment 1) clearly identify the criteria for setting load-responsive
protective relays? If not, provide specific detail that would improve the clarity of Table 1.
Yes
No
Comments:

Unofficial Comment Form
Project 2010-13.2 –Phase II Relay Loadability (Draft 3: PRC-025-1) April 25, 2013

6

3. Does PRC-025-1, Guidelines and Technical Basis provide a clear understanding of the
various criteria, including the options (e.g., 1a, 1b, 1c, 2a, etc.) for setting load-responsive
protective relays? If not, provide specific detail that would improve the Guidelines and
Technical Basis.
Yes
No
Comments:

4. The drafting team developed an Implementation Plan for the added requirements of the
proposed PRC-023-3 that aligns with that proposed in PRC-025-1. Do you agree with the
proposed Implementation Plan for PRC-023-3 Requirements R7 and R8 and the proposed
PRC-025-1:
a. 48-months to apply load-responsive protective relay settings , where relay
replacement is not required, and
b. 72-months to apply load-responsive protective relay settings, where relay
replacement is required?
If not, provide an alternative implementation plan with specific rationale for such an
alternative period.
Yes
No
Comments:
5. Do you have any other comments? If so, please provide suggested changes and rationale.
Yes
No
Comments:

Unofficial Comment Form
Project 2010-13.2 –Phase II Relay Loadability (Draft 3: PRC-025-1) April 25, 2013

7

Violation Risk Factor and Violation
Severity Level Justifications
PRC-023-3 – Transmission Relay Loadability
Project 2010-13.2 Phase II Relay Loadability

Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors 
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC‐023 – Transmission Relay 
Loadability. 

Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and 
FERC Guidelines when proposing VRFs and VSL for the requirements under this project. 

NERC Criteria – Violation Risk Factors

High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system 
instability, separation, or a cascading sequence of failures, or could place the bulk electric system 
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions 
anticipated by the preparations, directly cause or contribute to bulk electric system instability, 
separation, or a cascading sequence of failures, or could place the bulk electric system at an 
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a 
normal condition. 
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the 
bulk electric system, or the ability to effectively monitor and control the bulk electric system. 
However, violation of a medium risk requirement is unlikely to lead to bulk electric system 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if 
violated, could, under emergency, abnormal, or restorative conditions anticipated by the 
preparations, directly and adversely affect the electrical state or capability of the bulk electric 
system, or the ability to effectively monitor, control, or restore the bulk electric system. 

However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or 
restoration conditions anticipated by the preparations, to lead to bulk electric system 
instability, separation, or cascading failures, nor to hinder restoration to a normal condition. 

Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be 
expected to adversely affect the electrical state or capability of the bulk electric system, or the 
ability to effectively monitor and control the bulk electric system; or, a requirement that is 
administrative in nature and a requirement in a planning time frame that, if violated, would not, 
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be 
expected to adversely affect the electrical state or capability of the bulk electric system, or the 
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement 
that is administrative in nature. 

FERC Violation Risk Factor Guidelines

The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting 
VRFs:1 

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:2 


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 

1

 North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing 
Order”). 
 Id. at footnote 15. 

2

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

2



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. 

NERC Criteria – Violation Severity Levels

Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not 
achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs for 
each requirement, some requirements do not have multiple “degrees” of noncompliant 
performance, and may have only one, two, or three VSLs. 
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element 
(or a small percentage) of 
the required performance  
The performance or 
product measured has 
significant value as it 
almost meets the full 
intent of the requirement. 

Moderate
Missing at least one 
significant element (or a 
moderate percentage) of 
the required 
performance. 
The performance or 
product measured still has 
significant value in 
meeting the intent of the 
requirement. 

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

High
Missing more than one 
significant element (or is 
missing a high 
percentage) of the 
required performance or 
is missing a single vital 
component. 
The performance or 
product has limited value 
in meeting the intent of 
the requirement. 

Severe
Missing most or all of the 
significant elements (or a 
significant percentage) of 
the required 
performance. 
The performance 
measured does not meet 
the intent of the 
requirement or the 
product delivered cannot 
be used in meeting the 
intent of the requirement. 

3

FERC Order of Violation Severity Levels

FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed 
for each requirement in the standard meet the FERC Guidelines for assessing VSLs: 

Guideline 1 – Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may 
encourage a lower level of compliance than was required when levels of non‐compliance were 
used. 

Guideline 2 – Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant 
performance. 

Guideline 3 – Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLs should not expand on what is required in the requirement. 
Guideline 4 – Violation Severity Level Assignment Should Be Based on A Single
Violation, Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non‐compliance with a 
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing 
penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

4

VRF and VSL Justifications 

VRF Justifications – PRC‐023‐3, R7 
Proposed VRF 
NERC VRF 
Discussion 

High 
A Violation Risk Factor of High is consistent with the NERC VRF definition. 
Failure by an entity to apply load‐responsive protective relay settings in 
accordance with the proposed standard PRC‐025‐1, Attachment 1; Relay 
Settings, 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. 
The unnecessary tripping of protective relays on generators has often been 
determined to have expanded the scope and/or extended the duration of 
disturbances of the past 25 years. This was also noted to be a serious issue in 
the August 2003 “blackout” in the northeastern North American continent. 
This requirement is analogous with the proposed PRC‐025‐1, Attachment 1, 
Table 1, Options 14 through 19 for generator interconnection Facility(ies). The 
loss of the connection between the generator and the Transmission system 
can 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 VRF G1 
Discussion 

Guideline 1‐ Consistency w/ Blackout Report: 
This requirement is directly related to observations from the 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.  Further, 
this requirement addresses observations from the related reports that a 
number of generators tripped because of load‐responsive protective relays, 
and establishes criteria recognizing the dynamic performance of generators 
during stressed system conditions for lines which connect those generators to 
the transmission system. 

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

5

VRF Justifications – PRC‐023‐3, R7 
Proposed VRF 

High 

FERC VRF G2 
Discussion 

Guideline 2‐ Consistency within a Reliability Standard: 

FERC VRF G3 
Discussion 

Guideline 3‐ Consistency among Reliability Standards: 

FERC VRF G4 
Discussion 

Guideline 4‐ Consistency with NERC Definitions of VRFs 

FERC VRF G5 
Discussion 

Guideline 5‐ Treatment of Requirements that Co‐mingle More than One 
Obligation 

Requirements R1, R2, and R8 have similar reliability objectives and are 
assigned High VRFs. 

No other approved Reliability Standards address similar reliability goals.  
Requirement R1 of Draft Reliability Standard PRC‐025‐1 has a similar reliability 
goal, and is currently assigned a High VRF. 

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 R7 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. 

The proposed requirement does not co‐mingle more than one obligation. 

Proposed VSLs for PRC‐023‐3, R7 
R7 

R7 

Lower 

N/A 

Moderate 

N/A 

High 

N/A 

Severe 
The responsible entity did not set one of its generator 
interconnection Facility relays in accordance with the 
criteria in Attachment C. 

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

6

VSL Justifications – PRC‐023‐3, R7 
NERC VSL Guidelines 

The NERC VSL guidelines are satisfied by identifying 
noncompliance based on “pass‐fail” or a binary 
condition. The entity either “applied” or “did not apply” 
the setting(s) in accordance with PRC‐023‐3 Attachment 
C; therefore, the Violation Severity Level must be 
designated Severe. 

FERC VSL G1 

This is a new requirement.  However, the proposed VSL 
for Requirement R7 is consistent with the approved VSL 
for the similar Requirements R1 and R2 within PRC‐023‐
2. 

Violation Severity Level 
Assignments Should Not Have the 
Unintended Consequence of 
Lowering the Current Level of 
Compliance 
FERC VSL G2 

Guideline 2a: 

Violation Severity Level 
Assignments Should Ensure 
Uniformity and Consistency in the 
Determination of Penalties 

The proposed VSL is binary and assigns a “Severe” 
category for the violation of the requirement.  

Guideline 2b: 
Guideline 2a: The Single Violation 
Severity Level Assignment Category  The proposed VSL for Requirement R7 does not contain 
ambiguous language. 
for "Binary" Requirements Is Not 
Consistent 
Guideline 2b: Violation Severity 
Level Assignments that Contain 
Ambiguous Language 
FERC VSL G3 

The proposed VSL is consistent with the corresponding 
Violation Severity Level Assignment  Requirement, R7. 
Should Be Consistent with the 
Corresponding Requirement 
FERC VSL G4 

The proposed VSL is based on a single violation and not a 
Violation Severity Level Assignment  cumulative number of violations. 
Should Be Based on A Single 
Violation, Not on A Cumulative 
Number of Violations 
VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

7

VRF Justifications – PRC‐023‐3, R8 
Proposed VRF 
NERC VRF 
Discussion 

High 
A Violation Risk Factor of High is consistent with the NERC VRF definition. 
Failure by an entity to apply load‐responsive protective relay settings in 
accordance with the proposed standard PRC‐025‐1, Attachment 1; Relay 
Settings, 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. 
The unnecessary tripping of protective relays on generators has often been 
determined to have expanded the scope and/or extended the duration of 
disturbances of the past 25 years. This was also noted to be a serious issue in 
the August 2003 “blackout” in the northeastern North American continent. 
This requirement is analogous with the proposed PRC‐025‐1, Attachment 1, 
Table 1, Options 7 through 12 for generator interconnection Facility(ies). The 
loss of the connection between the generator and the Transmission system 
can 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 VRF G1 
Discussion 

Guideline 1‐ Consistency w/ Blackout Report: 
This requirement is directly related to observations from the 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.  Further, 
this requirement addresses observations from the related reports that a 
number of generators tripped because of load‐responsive protective relays, 
and establishes criteria recognizing the dynamic performance of generators 
during stressed system conditions for transformers which connect those 
generators to the transmission system. 

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

8

VRF Justifications – PRC‐023‐3, R8 
Proposed VRF 

High 

FERC VRF G2 
Discussion 

Guideline 2‐ Consistency within a Reliability Standard: 

FERC VRF G3 
Discussion 

Guideline 3‐ Consistency among Reliability Standards: 

FERC VRF G4 
Discussion 

Guideline 4‐ Consistency with NERC Definitions of VRFs 

FERC VRF G5 
Discussion 

Guideline 5‐ Treatment of Requirements that Co‐mingle More than One 
Obligation 

Requirements R1, R2, and R7 have similar reliability objectives and are 
assigned High VRFs. 

No other approved Reliability Standards address similar reliability goals.  
Requirement R1 of draft Reliability Standard PRC‐025‐1 has a similar reliability 
goal, and is currently assigned a High VRF. 

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 R8 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. 

The proposed requirement does not co‐mingle more than one obligation. 

Proposed VSLs for PRC‐023‐3, R8 
R8 

R8 

Lower 

N/A 

Moderate 

N/A 

High 

N/A 

Severe 
The responsible entity did not set one of its generator 
step‐up transformer relays in accordance with the 
criteria in Attachment C. 

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

9

VSL Justifications – PRC‐023‐3, R8 
NERC VSL Guidelines 

The NERC VSL guidelines are satisfied by identifying 
noncompliance based on “pass‐fail” or a binary 
condition. The entity either “applied” or “did not apply” 
the setting(s) in accordance with PRC‐023‐3 Attachment 
C; therefore, the Violation Severity Level must be 
designated Severe. 

FERC VSL G1 

This is a new requirement.  However, the proposed VSL 
for Requirement R8 is consistent with the approved VSL 
for the similar Requirements R1 and R2 within PRC‐023‐
2. 

Violation Severity Level 
Assignments Should Not Have the 
Unintended Consequence of 
Lowering the Current Level of 
Compliance 
FERC VSL G2 

Guideline 2a: 

Violation Severity Level 
Assignments Should Ensure 
Uniformity and Consistency in the 
Determination of Penalties 

The proposed VSL is binary and assigns a “Severe” 
category for the violation of the requirement. 
Guideline 2b: 

The proposed VSL for Requirement R8 does not contain 
Guideline 2a: The Single Violation 
ambiguous language. 
Severity Level Assignment Category 
for "Binary" Requirements Is Not 
Consistent 
Guideline 2b: Violation Severity 
Level Assignments that Contain 
Ambiguous Language 
FERC VSL G3 

The proposed VSL is consistent with the corresponding 
Violation Severity Level Assignment  Requirement, R8. 
Should Be Consistent with the 
Corresponding Requirement 
FERC VSL G4 

The proposed VSL is based on a single violation and not a 
Violation Severity Level Assignment  cumulative number of violations. 
Should Be Based on A Single 
Violation, Not on A Cumulative 
Number of Violations 
VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

10

VRF and VSL Justifications (Draft 2: PRC‐023‐3) 
Project 2010‐13.2 – Phase II Relay Loadability (April 24, 2013) 

11

Standards Announcement

Project 2010-13.2 – Phase 2 of Relay Loadability: Generation
PRC-023-3 & PRC-025-1
Formal Comment Period for PRC-025-1 and PRC-023-3: April 25, 2013 – May 24, 2013

Upcoming:
Successive Ballot and Non-Binding Poll for PRC-025-1: May 15, 2013 – May 24, 2013
Now Available

A 30-day formal comment period is open for PRC-023-3 – Transmission Relay Loadability and PRC-0251 – Generator Relay Loadability through 8 p.m. Eastern on Friday, May 24, 2013.
Background information for this project can be found on the project page.
Instructions for Commenting
A formal comment period for PRC-023-3 and PRC-025-1 is open through 8 p.m. Eastern on Friday, May
24, 2013. Please use this electronic form to submit comments. If you experience any difficulties in
using the electronic form, please contact Wendy Muller at [email protected]. An off-line,
unofficial copy of the comment form is posted on the project page.
Next Steps

A successive ballot of PRC-025-1 and non-binding poll of the associated VRFs and VSLs will be
conducted from May 15, 2013 through May 24, 2013.
Standards Development Process

The Standards 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Name (31 Responses)
Organization (31 Responses)
Group Name (50 Responses)
Lead Contact (50 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (9 Responses)
Comments (50 Responses)
Question 1 (37 Responses)
Question 1 Comments (50 Responses)
Question 2 (33 Responses)
Question 2 Comments (50 Responses)
Question 3 (33 Responses)
Question 3 Comments (50 Responses)
Question 4 (32 Responses)
Question 4 Comments (50 Responses)
Question 5 (39 Responses)
Question 5 Comments (50 Responses)

Texas Reliability Entity
Texas Reliability Entity
NA
NA

No
(1) Texas RE objects to the use of the term Regional Reliability Organization (RRO) in Table 1. RRO is
an obsolete term that NERC had been trying to purge from the standards, and we are somewhat
alarmed to see it used in a new place in the standards. While we recognize that RRO is defined in the
Glossary, it is not in the functional model and, at least in our region, it does not identify any entity
and it is ambiguous. We urge you to replace the term RRO with an entity type from the functional
model, or to write a description of what is intended without using the term "RRO". (2) Regarding the
“Transformers” section on page 7 and footnote 3 on page 10, consider whether it is appropriate to
use the “nameplate impedance at the nominal GSU turns ratio” in all instances. In some cases, it is
more appropriate to use the calculated (i.e. with compensation) impedance that reflects the lowest
value based on the de-energized tap and LTC tap positions for this purpose. (3) For Options 1a, 2a,
and 7a, consider using 0.9 per unit instead of 0.95 per unit, because typical disturbance (postcontingency) voltage criterion is 0.9 p.u. (4) Consider clarifying that the Real Power output criteria
should be based on the [highest seasonal] MW rating for the applicable unit. There can be significant
seasonal variations in MW capabilities for some units. We don’t expect pickup settings to be changed
from season to season, so an appropriate year-round setting should be determined and applied. (5)
Some transmission systems have steady state stability limits that encroach into the generator
capability limits. Consider adding exclusion criteria for these types of scenarios.

Texas RE generally supports this standard as written, other than the use of the term *Regional
Reliability Organization* in Table 1 as described above. Our other comments are provided for
consideration by the drafting team.
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Pamela R. Hunter
Yes

Yes
Yes

Yes
2) We suggest removing Section 3.2.3 and footnote 1. UAT protection is part of the station service
system and should not be in this standard. Remove the UAT from Table 1. The UAT relays are not in
the category of “all load-responsive protective relays that are affected by increased generator output
in response to system disturbances.” The highside overcurrent pickup should not be required to be at
150%. Settings at > & = 115% should be allowed. 3) We believe that the Purpose statement should
end "… do not pose a risk of damaging the generator." 4) The protection of the generator should be
the paramount concern. All ANSI standards for generator and main power transformer protection
should be considered to be the ruling guide for protecting the equipment. The minimum allowable
settings provided in the table in the draft standard do not factor using time delays in order to provide
adequate protection for generators. 5) The overload relay that protects the generator from overload
may also be the relay that protects the GSU from overload. In the exception list of the draft standard,
exception bullet #5 should take precedence over exception bullet #6. 6) The protection requirements
(exception bullet #5) from the ANSI standards need additional recognition, development, and
emphasis in the Exceptions section. As written, it appears to be an afterthought. The ANSI standard
for synchronous generator protection should be recognized, respected, and not violated. The Table 1
setting specifications which contradict the ANSI standards should be submissive to the ANSI
standards and itemized in the exception criteria. Consider removing “extremely” from the "extremely
inverse time" description as various vendors call the varying inverse time curve by different names.
7) The generator overload protection exception added to Draft 3 for extremely inverse characteristics
(fifth exception bullet) is an improvement, but the term “full-load current” needs clarification. Is this
the current at normal full-load turbine output and typical PF, the value determined from the generator
nameplate MVA at rated voltage, or is it the base or top (no fans, no oil circulation) MVA rating of the
GSU? 8) The wording in the sixth exception bullet of the Exceptions section is too vague. How much
of an overload is considered an overload? Many vendor relay curves do not provide characteristics
showing the value of current that will time out in 15 minutes. It may be difficult to prove a setting to
provide 15 minute delay. Existing relays in service do not have the ability to be set by this criterion.
9) The Exceptions section seems to state that the exceptions are allowed only during start up and
when off line, which is unacceptable. The exceptions should be allowed at all times. 10) To meet the
requirements of table 1 for non-51 relays (distance relays set at approximately 180% of generator
MVA) and meet our protection philosoply objectives, we would have to install many new relays for
overload protection. 11) Determination of the pickup of the distance relays is too complicated. The
calculated impedance should be based on generator nameplate MVA and pf only. The requirements
make what should be a simple calculation based on generator electrical characteristics into one that
will require the relay engineer to find test MW data is not readily unavailable. 12) PRC-025 should be
revised to "grandfather" existing protection settings that have been proven in practice for many
decades not to prematurely remove equipment from service. 13) The applicability of PRC-025 should
exclude small gensets that are NERC-registered solely due to being black start-capable, whose
tripping would not meaningfully affect the ability of the system to ride through Disturbances. It would
be best to allow such units to maintain their present loadability relay settings for retoration purposes.
14) Voltage-restrained overcurrent relays are notorious for not having a predictable operation time
under fault conditions. If they are included in the types of equipment that mis-operated in the August
2003 blackout, they should be required to be replaced with another relay type rather than requiring
that the settings be relaxed to the degree specified in the draft standard. 15) A High VRF and a
Severe VSL seems overly harsh given the compliance feasibility uncertainties. 16) Which UATs are
proposed to be included, if any, is confusing. Suggest adding diagrams to the reference document.
17) During the webinar there were three slides related to the different trans to Gen interconnections
and who is responsible for what; suggest adding and or clarifying these in the reference documents.
Vladimir Stanisic
AESI Inc.
na

na
Yes
No
The team is commended for an extensive effort to provide high level of detail through numerous relay
setting examples summarized in Table 1 and elaborated in the document
PRC_025_1_Guidlines_and_Technical_Basis_Draft_3_2013_04_24_Redline.pdf. Nonetheless, the
following points may need further attention: 1. The settings derived by simulations versus the
settings derived by manual calculations are noticeably different, the latter being repeatedly much
more conservative (e.g. 8c: 6.6 A pu versus 8a: 9.5 A pu), exposing generators to a higher risk of
overloading. It would be expected that the results of manual calculations and simulations would yield
closer values, at least for most of typical configurations. It appears that underlying assumptions used
in the calculations and simulations may need to be fine-tuned. For example, is it realistic to have field
forcing producing 1.5 pu MVAR output and at the same time generator bus voltage at 0.95 pu. 2. The
settings derived by manual calculations are such the generators are exposed to a higher risk of
overloading: • Example 1a – 21 protection would operate only when unit loading exceeds approx.
280% (at rated power factor). • Example 2a – 51V protection pickup is set at equivalent of approx.
170% loading. Taking into account that overcurrent relays actually react when current exceeds 1.5
pickup setting, equivalent loading on the unit would have to exceed 250% before timing is initiated.
Depending on the relay characteristic, time delay can be significant. 3. C37.102 states that acceptable
settings for 21 function are 150% to 200% (at rated power factor). These values should guide the
requirements of this standard. 4. The Table specifies pickup setting criteria. It remains unclear when
are the relays allowed to trip. 5. Examples 7a, b, c, seem to be duplication of 1a, b, c. 6. The
following comment from the Guidelines document is not clear: ====== Options 7a and 10, Table 1 –
Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for generator bus voltage,
***however due to the presence synchronous generator 0.95 per unit bus voltage will be used as
(Vgen)***?: ==========
No
Please see comments on Question 2.
Yes
Yes
This draft of the standard uses 0.85 pu transmission system voltage as a benchmark for determining
the settings. The latest version of PRC-024-1 defines post-disturbance voltage profile where the
system voltage is below 0.85 pu up to 3 seconds. Is there a need to take that into consideration for
this standard.
Northeast Power Coordinating Council
Guy Zito

Yes
In PRC-023-3, add “Each” to the beginning of R8.
Pepco Holdings Inc. & Afffiliates
David Thorne
No
1 ) The inclusion of Requirements R7 and R8 and the entire Table 1 from PRC-025-1 overly
complicates PRC-023-3. In addition, inclusion of these Table 1 requirements without the
corresponding Guidelines and Technical Basis document produced for PRC-025 makes the application

of Table 1 in PRC-023 difficult, if not impossible. The intent of the original PRC-023 was to apply to
owners of load responsive relays (whether they be TO’s or GO’s) that are applied on BES transmission
circuits and BES power transformers. The new PRC-025 standard should apply to owners of load
responsive relays (whether they be TO’s or GO’s) that are applied on BES generators, GSUs, UAT’s
and Generator Interconnection Facilities. In a good faith effort to provide a bright line between the
two standards, the new PRC-023-3 standard became overly complicated and extremely confusing. It
would seem that instead of adding PRC-025 requirements to PRC-023, it would be much simpler to
just add Transmission Owners to the Applicability Entities section of PRC-025. The Applicable Facilities
section of each standard should identify that any load responsive relay (whether they are owned by
GO’s or TO’s) installed on these types of facilities must comply with the respective requirements of
that standard. If this were done then the original PRC-023 could be revised to exclude relays installed
on generators, GSU’s, UAT’s and Generator Interconnection Facilities, as they will be covered by PRC025. PRC-023 would apply solely to owners of load responsive relays (whether they be TO’s or GO’s)
that are applied on BES transmission circuits and BES power transformers. 2 ) It is unnecessary to
remove Criterion 6 from PRC-023-3 as it represents an acceptable alternative to the methods offered
in PRC-025. When load responsive relays are set on transmission line terminals connected to
generation stations remote from load in accordance with Criterion 6 of PRC-023 (230% of aggregate
generation nameplate capability) the resulting setting provides sufficient margin to accommodate
acceptable loadability. This criterion has been successfully used for years and has gone through the
full standards development process and been vetted as an acceptable alternative. Consider the
example calculation for Option 14a in PRC-025. From Equation 112 the apparent primary impedance
seen by the relay on the high side of the GSU is 74.3 ohms primary at an angle of 52.77 degrees.
Now assume the 230% method from PRC-023 Criterion 6 was used instead. The new apparent power
would be 2.3 x (767.6 MW + j 475.6 MVAR) = 2.3 x 903 MVA =2076.9 MVA at an angle of 31.8
degrees. Using Equation 112 the apparent primary impedance would be 41.4 ohms at 31.8 degrees.
From Equation 115 the setting required to satisfy Option 14a criteria from PRC-025 would be 15.283
ohms sec = 76.42 ohms primary at 85 degrees. The reach of this relay along the 31.8 degree load
angle would be 76.42 x Cos (85 – 31.8) = 45.77 ohms primary. Since this is greater than the 41.4
ohm setting resulting from Criterion 6 of PRC-023, the PRC-023 Criterion is slightly more
conservative, requiring a slightly smaller relay reach than Option 14a. As such, both methods should
be considered equally effective in ensuring relay loadability.
No
For the PRC-025 standard the inclusion of Table 1 along with the Figures and Example Calculations in
the Guidelines and Technical Basis document clearly identifies the proposed setting criteria. However,
the inclusion of Table 1 in PRC-023 overly complicates the scope of PRC-023, and without inclusion of
the corresponding Guidelines and Technical Basis document makes application of Table 1 criteria
difficult. We feel strongly that all references to load responsive relays applied on generators, GSU’s,
UAT’s and Generation Interconnection Facilities (including Table 1 and Requirements R7 and R8)
should be eliminated from PRC-023 as they are already adequately covered in PRC-025. Transmission
Owners that own load responsive relays on those types of facilities should be included as an
Applicable Entity under PRC-025. (See comments submitted for Question 1).
No
1 ) The new term “Generator Interconnection Facilities” is not defined in the NERC Glossary of terms,
nor is it defined in the body of the standard. It is defined in the Guidelines and Technical Basis
document; however, we feel this term needs to be defined within the body of the standard itself.
Perhaps a footnote similar to that used to define Unit Auxiliary Transformers would be appropriate.
We would suggest the same definition used in the Guidelines and Technical Basis document be
inserted: “Generator interconnection Facility(ies) consists of Elements between the generator step-up
transformer and the interface with the portion of the bulk Electric System (BES) where Transmission
Owners take over the ownership.” 2 ) In Figures 4 and 5 the CT’s supplying the 21, 51V-R and 51V-C
relays connected to the generator(s) look like they are connected to the generator neutral. To make it
clear that they are supplied from CT’s connected in the phase leads, a phase to neutral transition
symbol (ref Fig 7.4 in IEEE C37.102) should be used to indicate the CTs are located above the neutral
connection point. 3 ) In Figure 5 there is a 51 relay shown connected to the 22kV bus leads supplying
the generator on the left hand side of the drawing. This 51 relay is not reverenced, or used, in any of
the options and therefore should be removed from the drawing. 4 ) Options 14a, 14b, 15a, 15b, 16a
and 16b all use an MVAR value equal to 120% of the aggregate generation MW value, instead of the

150% value used when the relays are located on the generator side of the GSU transformer.
Presumably this is to account for the I squared Xt MVAR loss consumed in the GSU transformer.
However, there is no mention of this fact in the Guidelines and Technical Basis document. To avoid
confusion as to why different MVAR criteria are used, supporting technical justification / explanation
should be offered in the document. 5 ) The example calculations for Options 4 and 10 are combined
as a single identical set of calculations. This calculation is appropriate for Option 10 but not for Option
4. Referring to Figure 5, the 21 relays for Option 4 are shown connected to each individual generator.
Also the 20MVAR static compensation source is connected upstream of each generator relay. As such,
the 21 relay on each individual generator (Option 4) will only see the MW and MVAR flows from a
single generator, not the aggregate of all the generation plus the 20MAR reactive source. A separate
calculation for Option 4 should be developed. For that Option 4 case the single generator apparent
power (assuming three generators of equal size) would be 102/3 = 34 MW and 63.2/3 = 21 MVAR,
which is 40 MVA for each generator. 6 ) The example calculations for Option 5 appear to be incorrect.
Again referring to Figure 5, the 51V-R relays for Option 5 are shown connected to each individual
generator. Also the 20MVAR static compensation source is connected upstream of each generator
relay. As such, the 51V-R relay on each individual generator (Option 5) will only see the MW and
MVAR flows from a single generator, not the aggregate of all the generation plus the 20MAR reactive
source. As such the 51V-R relay should be set to 130% of the maximum MVA rating of that individual
generator. Again assuming three units of equal size, each generator would be rated 40MVA and
therefore the 51V-R relay should be set to not operate below 1.3 x 40 = 52 MVA 7 ) The example
calculations for Options 7a, 10, 8a, 9a, 11, and 12 illustrate a mixture of synchronous and
asynchronous generators. However, there is no corresponding one-line drawing which corresponds to
these examples. Because of this, it is difficult visualize the topology of this arrangement and where
the corresponding relays would be located. If the SDT wishes to provide an example calculation where
there is a mix of synchronous and asynchronous generation then we would suggest an additional
figure be added (Figure 6) which would illustrate this type of connection.
Yes
No
FirstEnergy
Doug Hohlbaugh
No
FirstEnergy (FE) appreciates the attempt to develop a bright-line method but feel the approach taken
is over complicating the standards. FE believes that the changes made to PRC-023 with the inclusion
of requirements R7 and R8 and the associated Attachment C cause unnecessary confusion. FE
proposes that the team remove R7, R8 and Attachment C from PRC-023 and retain a modified version
of PRC-023, R1 item 6. Further, as supported in our comments below, we encourage the team to limit
the applicability of PRC-023 to the TO and DP and the applicability of PRC-025 to the GO. FE believes
it is imperative for NERC to develop its standards in a consistent approach in regard to terminology
that is deemed “transmission” and those deemed “generation”. We are concerned that the proposed
changes to PRC-023 and PRC-025 overly complicate what most in industry already understand to be
“transmission” and “generation” facilities. For example, NERC recently proposed errata changes to
PRC-004 and PRC-005 to clarify that for a GO the requirements of those standards extend not only to
protection systems associated with the generating facility or station itself, but also to any protection
systems associated with the generator interconnection facility. It’s difficult to understand why PRC004 and PRC-005 seem to have clear TO and GO boundaries when it comes to reporting relay
misoperations and performing relay maintenance, yet when ensuring relay loadability requirements
are met things all of a sudden become much more complicated. To date, generation interconnection
facility(ies) as used in NERC standards are generator owner assets, “generator lead”, operated at
transmission voltage levels. However, if the generator lead happens to be owned by a transmission
owner, then it’s understood simply to be a transmission line or transmission facility. The two relay
loadability standards should maintain this same simplicity and PRC-023 should apply only to TO/DP
and PRC-025 to the GO. We suggest that the team take this opportunity to introduce a formally
defined NERC Glossary Term for generator interconnection facility. During the recent webinar the

team spent a fair amount of time indicating that when evaluating a generator interconnection
facility(ies) as shown in Figure 1 and Figure 2 that it essentially comes down to the relay owner when
determining which standard (PRC-023 or PRC-025) is applicable. The team indicated that if the GO
owns the relay for line breaker(s) at Bus A then PRC-025 applies, but if the DP/TO owns the relay
then PRC-023 applies. The team further described that the GO was left in PRC-023 to handle a
situation where they may own relaying for line breaker(s) on networked transmission lines as shown
in Figure 3. The team also cited they retained the GO for this situation to avoid a potential
“registration tension”. The perceived need for the GO in standard PRC-023 calls into question the
facility rating for the network transmission line as established under FAC-008-3. NERC standards must
maintain consistent philosophies in terminology throughout all standards and cover the most common
system configurations. Any unique situations will need to be dealt with on a case by case basis
between asset owners. Additionally, NERC drafting teams should not be writing standards to cover
one-off configurations simply to address potential entity registration concerns. While FE strongly
objects to the use of R7, R8 and Attachment C in PRC-023, if the team does not agree with our
proposal to remove the GO completely from PRC-023 then as an alternate approach we support
comments filed by Pepco Holdings, Inc. – PHI which suggesting adding the TO/DP to PRC-025 and
removing R7, R8 and Attachment C from PRC-023. Either approach (FE’s or PHI’s) requires retaining
item 6 of R1 in PRC-023. In summary, for PRC-023, FE proposes the following: 1.) Remove the
Generator Owner applicability 2.) Remove Requirements 7 and 8 since they will be included in PRC025 3.) Remove Attachment C 4.) Change Requirement 1 Criteria #6 to read as follows: “Set
transmission line relays applied on transmission lines connected to generation stations remote to load
directional towards the generator so they do not operate at or below 115% of the rating of the
generator as calculated according to applicable NERC standards.” Although not our preferred option,
we also recommend the team considered the suggestion by PHI that would add the TO as an
applicable entity to PRC-025 while also removing PRC-023 R7, R8 and Attachment C.
No
As stated above (Question 1) FE does not support the inclusion of Attachment C in PRC-023. See
question 1 for more information. From a technical standpoint, we support Table 1 of PRC-025.
Yes
Yes
Yes
FE believes that that the term "generator interconnection Facility" should be a NERC defined term in
the Glossary since it is used in other standards, ie, PRC-005, or at the very least, be defined within
the standard(s). This term is only defined in the Guidelines and Technical Basis. In the Guidelines and
Technical Basis, Figure 2 has a typo on the 3rd sentence and should read as follows: If the
Distribution Provider or Transmission Owner owns these relay, they are responsible for them under
PRC-023.
John Yale
Chelan County PUD
none
none
No
It seems that GSU and UAT would be subject to PRC-023 and PRC-025. It would be cleaner if one
standard applied to GSU and UAT and the other to the transmission circuits.
Yes

Yes
Yes

1. Please, reconsider the applicaiton to small units that are "black start" or auxiliary units in a BES
plant. Application of these requirements to a small (750kW) hydro unit that is black start is
problamatic particularly due to the age of many of these units. It is difficult to see where loss of a unit
of small size would impact the BES during this type of event. Please, consider a minimum size
threshold for units where these requirements would be applicable. Perhaps 20MW as is used in the
BES definition would be appropirate. Consider also an exclusion for a small unit, say less than 5MW,
that is part of an aggregate plant of larger units that exceeds the 75MW plant threshold. An example
is our 750kW hydro unit that is in the plant with ten 25MW units. It seems excessive to apply this to
the 750kW unit. 2. UATs should be dropped from the standard. The Application Guidelines state that
the reliability objective of PRC-025 is to cover, “all load-responsive protective relays that are affected
by increased generator output in response to system disturbances,” but the relays of UATs are not in
this category. A disturbance on the HV system would not affect the real or reactive power draws of
auxiliary loads, and it was stated in the 12/13/2012 webinar that UAT relay trips are not known to
have caused the loss of any generation units during the northeast blackout of ’03. UATs are stated
later in the Application Guidelines to have been included to satisfy a FERC directive (Order No. 733,
paragraph 104), but such a move nonetheless appears to be incorrect, particularly in light of NERC’s
recent emphasis on the cost justification of reliability standards. 3. Clarify UAT and station service
transformers. Footnote 1 says "Loss of these transformers will result in removing the generator from
service." Does that mean it only applies to SS transformers that loss of will remove a unit from
service? What about provisions for backup, multiple transformers and busses? Consider an hydro
plant with 4 sation service busses and 12 generating units. Would this standard apply to all? This is
very different from thermal stations where a unit would have a dedicated transformer that without its
power the unit will trip. Consider liminting this only to transformers where loss would cause a direct
trip of a BES unit, or eleminiate UAT ans SS transformers completely per comment 2. 4. The
generator overload protection exception added to Draft 3 for extremely inverse characteristics (5th
bull-dot) is a major improvement, but the term “full-load current” needs clarification. Is this the
current at normal full-load turbine output and typical PF, or the value determined from the generator
nameplate MVA at rated voltage, or the base (no fans, no oil circulation) rating of the GSU, or FERC
hydro nameplate criteria at best gate? 5. PRC-025 should be revised to grandfather existing major
equipment, similar to the approach recently used for PRC-024. It may not always be possible to
develop PRC-025-conforming means of protection without replacing GSUs or UATs; and, in the
absence of any compensation to the owner, it would be inappropriate to outlaw equipment that was
acceptable under the rules in effect at the time it was installed. 6. Deeming any and all violations of
this standard to have a high violation risk factor and a severe violation severity level seems overly
harsh, given the compliance feasibility uncertainties expressed above. Consider a VSL based on the
size of the generating unit or amount of generation that would be lost if the standard were not
properly applied. A 20MVA unit would have a much lower impact on the reliability of the BES than a
500MW unit.
Barbara Kedrowski
Wisconsin Electric
Wisconsin Electric
Barb Kedrowski
Agree
NAGF

Operational Compliance
Ed Croft
Yes
Content is good. However - the two standards should refer to EXACTLY the same table of Relay
Loadability Evaluation Criteria with EXACTLY the SAME OPTION #s for each Relay Type/Application.

The table could stand on its own and each record be labeled with PRC-025 and/or PRC-023
applicability (new column(s)).
Yes
But...see comments for Question #1.
Yes
See comments for Question #1. In addition, Figures 1,2 and 3 could be clarified by 1) labelling the
Generator Interconnection Facility with a pointer and parentheses, 2) include table with columns for
Relay Owners, Function of Owner and Applicable Standard. This way, a quick glance at the figure can
clarify which standard is applicable (rather than having to decipher the caption).
Yes
Editorial note: To aid with distinguishing between options: underline the words “is necessary” and “is
not necessary” for “Implementation Date” columns.
Clem Cassmeyer
Western Farmers Electric Cooperative
Western Farmers Electric Cooperative
Caleb Muckala
Agree
Western Farmers Electric Cooperative
No
See comments to question 5
No
See comments to question 5
Yes
Many generation Facilities, that are part of the Bulk Electric System, became commercial in the
1950’s, 1960’s, 1970’s, 1980’s and 1990’s. These Facilities should be Grandfathered in. Many of these
units, although reliable, it may not be cost effective to obtain compliance with PRC-025-1. Many of
these Facilities would be forced to either: (1) implement very expensive upgrades to existing
equipment, (2) replace existing equipment, (3) retire the Facility. It’s my opinion this is not consistent
with the economic rational NERC is attempting to achieve. Secondly, the Violation Risk Factor of High,
seems extreme because several other standards address generator reliability (Under-frequency,
Misoperations, Protection System Maintenance and Testing, Generator Verification). These standards,
have resulted in many generation Facilities having undergone relay coordination studies to prevent an
occurrence similar to the 2003 “blackout.”
Michael Mayer
Delmarva Power & Light Company
Pepco Holdings Inc & Affiliates
David Thorne
Agree
Pepco Holdings Inc. & Affiliates

NICOLE BUCKMAN
Atlantic City Electric Company
Pepco Holdings inc. & Affiliates
David Thorne

Agree
Pepco Holdings Inc. and Affiliates

MRO NERC Standards Review Forum
Russel Mountjoy
Yes
Yes
Yes
Yes
The NSRF remains concerned that the proposed calculations for the distance relays will adversely
affect reliability of the BES by requiring generators to pull back distance reaches too far which could
lead to reduced rely coverage (at least for backup relaying) or longer delays for coordination. Some
sample calculations performed by NSRF members show that distance reaches need to be pulled back
more than 30%. The NSRF members believe that this is most likely due to the more conservative
relay load limit angle calculations at 30 degrees rather than former MidContinent Area Power Pool
(MAPP) criteria which used line Maximum Torque Angle calculations which typically averaged near 70
– 85 degrees. Sample MAPP Relay Load Limit Calculation: (0.85*kV)^2 / (Z1max*cos(max torque
angle – line power factor angle) NSRF sample calculations show that many generators may require 21
distance setting changes based upon this proposed standard, potentially resulting in potential
reductions of relay backup coverage for lines leaving some generating stations. This will put a much
higher risk and responsibility on the TO too have extremely reliable protection for the lines. We will no
longer be able to trip the generator off in a backup mode if the TO does not clear the phase fault at
end of line. This appears to conflict with R1, unless the standard is mandating the installation of
additional equipment such as redundant relays systems to maintain reliable fault protection. The
NSRF would ask the NERC Standard drafting team to work with NSRF members to help verify the
basis for the new calculations and if this does in fact reduce relay coverage or require entities to
install additional relaying to maintain system reliability as mandated in R1.
Mark Yerger
Potomac Electric Power Company
Pepco Holdings, Inc & Affiliates
David Thorne
Agree
Pepco Holdings Inc. and Affiliates

Jonathan Meyer
Idaho Power Company
n/a
n/a

Yes
Yes
Yes
Yes
No
Alice Ireland
Xcel Energy
n/a
Alice Ireland
Yes
No
For 51 relay that is installed on the high side of GSU, we suggest it should be an acceptable option if
the 51 relay setting meets R1 Criteria 11.
No
In the last paragraph on page 19 of the clean version of the PRC-025-1 Guidelines and Technical
Basis, the following sentence appears: "Phase time overcurrent relays applied to the UAT that act to
trip the generator directly or via lockout or auxiliary tripping relay are to be compliant with the relay
setting criteria in this standard." This typically would be the case for UAT's connected to the generator
bus. However, for system connected auxiliary transformers as shown in Fig 6 on page 20, it is very
unlikely that the time overcurrent relays protecting the system connected transformers will act to trip
the generator directly or via lockout as this is a different zone of protection and to do so might result
in an unnecessary challenge of the unit's overspeed protection. Instead, these overcurrent relays will
trip the source breakers feeding the system connected auxiliary transformer but will not act to directly
trip the generator. The generator will ultimately trip because of the resultant loss of power to the
auxiliary system when the source breakers feeding the auxiliary transformer are tripped. The loss of
auxiliary power will likely result in some form of a turbine/prime move trip and the generator breaker
will be tripped open once power output drops to zero. In this manner, unit overspeed protection is not
unnecessarily challenged. It seems that the quoted sentence on page 19 only serves to confuse the
matter. If the goal of this setting requirement is to not to have the plant trip due to a loss of auxiliary
power based on overly conservative setting of overcurrent relays, it is immaterial whether the
overcurrent relays act to trip the generator directly or via lockout or auxiliary tripping relay or if the
plant ultimately trips because a loss of auxiliary power caused by overcurrent relays opening source
breakers to the system connected auxiliary transformer. We recommend the quoted sentence be
stricken from the guideline and technical basis document.
Yes
Yes
1) Applicability: In the applicability sections, we suggest you replace the phrase "BES generating unit
or generating plant" with "BES generating unit or BES generating plant" to be more clear. 2) M1: We
recommend you add “simulation results” as acceptable evidence in Measure M1. (reason: Some
people may choose to do PRC023 check in the CAPE simulation.)
Michael Falvo
Independent Electricity System Operator
NPCC

Michael Falvo
Yes
Yes
Yes
Yes
No
PacifiCorp
Ryan Millard
Yes
Yes
Yes
Yes
No
Wryan Feil
Northeast Utilities
Wryan Feil
Wryan Feil
Yes
Yes
Yes
Yes
No
SERC Protection and Controls Subcommittee
David Greene
Yes
No
There is a discrepancy between the relay functions listed in PRC-023-3 Attachment A and those
identified in PRC-023-3 Attachment C Table 1 and PRC-025-1 Attachment 1 Table 1. PRC-023-3
Attachment A includes under 1.6, “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.” These schemes are not accounted for in the Table 1 of either proposed standard.
Given these schemes are required to meet loadability criteria on transmission lines not meeting the
“generator interconnection facility” designation (i.e. networked lines), the exclusion of the schemes
from generator loadability criteria creates confusion. Loadability criteria should be included for “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” in Table 1 of both PRC-023-3 and
PRC-025-1.
Yes
Yes
Yes
There were three one-line reference drawings described on the webinar. Suggest adding text to these
reference drawings or add descriptive wording in reference documents to better explain
responsibilities of relay owners for these various configurations. On the webinar there were repetitive
questions about these configurations so this would indicate confusion. Also, would suggest adding
another drawing to illustrate when you have a generating station where the GO owns GSU relays and
the TO owns relays between the GSU and switchyard to clarify that the TO is only responsible for R7
in PRC023-3 and not R8 since the GSU relays are a GO asset.
Nazra Gladu
Manitoba Hydro
Manitoba Hydro
Nazra Gladu
Yes
Yes
(1) Manitoba Hydro suggests eliminating Table 1 from one of the standards and referencing it in the
other standard, since both PRC-023-3 and PRC-025-1 are already very lengthy standards.
Yes
Yes
Yes
(1) Section 3.1.1, PRC-025-01 - the repeated word “Facilities” seems unnecessary. For clarity,
remove the last instance of the word “Facilities” in the statement: “Generator Owner that applies
load-responsive protective relays at the terminals of Facilities listed in 3.2, Facilities.” (2) Section 3.2
- it would be useful to add criteria that define which generator units should be included as associated
with the BES. Alternatively, should this standard refer to the BES definition for which generator units
in this standard will apply to? (3) Section 3.2.5 - It is unclear what elements should be included in
this section - Collector lines only? What size (MVA) of generating source that the collector line has to
be on to qualify as one of these elements? (4) Implementation Plan, PRC-023-3 - it would be helpful
to include the implementation plan within the standard. (5) PRC-023-3, Purpose - suggest re-wording
to the following “…not interfere with a system operators ability to take remedial action to protect
system reliability….”. (6) PRC-023-3, Purpose - capitalize “system operator” because it appears in the
Glossary of Terms. (7) PRC-023-3, Applicability, Functional Entity - capitalize “protection system”
because it appears in the Glossary of Terms. (8) PRC-023-3, 4.2.1.3 - ‘BES’ should be written Bulk
Electric System (BES) since it is the first appearance of the word. (9) PRC-023-3, 4.2.3.1 - should
Transmission lines be written “Transmission lines (and paths)”? (10) PRC-023-3, R1, 4 - capitalize the
words “power transfer capability” because it appears in the Glossary of Terms. (11) PRC-023 and
PRC-025 - capitalize the words “transmission lines” throughout the document(s). (12) PRC-023 and

PRC-025, D. Compliance 1.1 - the paraphrased definition of ‘Compliance Enforcement Authority’ from
the Rules of Procedure is not the standard language for this section. Is there a reason that the
standard CEA language is not being used? (13) PRC-023-3 — Attachment B, Circuits to Evaluate replace the acronym “BES” with the words “Bulk Electric System”. (14) PRC-023-3 — Attachment B,
Criteria, B2 - write out the words for “IROL” then use the acronym thereafter. (15) PRC-023-3 —
Attachment C - use the acronym “RRO” after the first instance of the words “Regional Reliability
Organization”. (16) PRC-025-1 – Attachment 1: Relay Settings - use the acronym “RRO” after the
first instance of the words “Regional Reliability Organization”.
Anthony Jablonski
ReliabilityFirst
ReliabilityFirst
Anthony Jablonski
Yes
Yes
No
1) There appears to be an error in the Guidelines and Technical Basis document on page 23 for option
15b. It indicates that the Reactive Power output that equates 120% of the maximum gross Mvar
output whereas Table 1 states 100%. 2) A statement should be inserted that the iterative calculation
stopped because the change was < 1%. This applies to options 1b & 7b on page 31 and option 2b on
page 38. Also, if an entity knows the resistive and reactive impedances of the transformer, the entity
could directly calculate the low-side GSU voltage from the high-side voltage, the per unit current
through the GSU and the full impedance of the transformer.
Yes
Yes
1) In Attachment 1, it is not clear that the fifth bulleted exception regarding protection systems that
detect generator overloads needs or should be as specific as to cite the 7 seconds at 218% of full-load
current operating point or characteristic curve. Typically for a fault right on the generator terminals,
the current decays in a couple of seconds to around full load current even with the AVR in service.
Even during field forcing, it is more likely that the field overcurrent relay would operate rather than a
generator overload relay. Therefore, the exclusion does not appear to be needed. If the exclusion is
needed, it is recommended that the exclusion be stated in a more general way such as the following:
Protection systems that detect generator overloads that are designed to coordinate with the generator
short-time capability by utilizing a relay characteristic set to operate no faster than the capability
curve and supervised to prevent operation below 115% of full-load current. 2) The word ‘Each’
appears to be missing in Requirement R8 of PRC-023-3. ‘Each’ should be inserted at the beginning of
the requirement before Transmission Owner and Distribution Provider. 3) Since there are cases where
redundant UATs that allow a generator to continue to remain in service when one UAT trips, this may
be rationale to revise 3.2.3 of the Applicability section to indicate exclusion for these configurations.
Alternatively, it could be addressed in the Guidelines and Technical Basis document. 4) The Regional
Reliability Organization (RRO) is referenced within both standards and it was ReliabilityFirst’s
understanding that the term RRO was to be removed from all the standards. In Order 693,
Paragraphs 146-148 and paragraph 157 state “The Commission adopts the NOPR proposal to
eliminate references to the regional reliability organization as a responsible entity in the Reliability
Standards. We conclude that this approach is appropriate because, as explained in the NOPR, such
entities are not users, owners or operators of the Bulk-Power System. NERC indicates that it can
remove such references, except that the Regional Entity should be identified as the compliance
monitor where appropriate.” ReliabilityFirst suggests replacing the RRO with the Planning Coordinator
(PC) or other registered function the SDT determines to have the wide area view and be responsible
for determining what these settings and or values should be.
David Jendras

Ameren
Ameren Compliance
Eric Scott
No
(1) For consistency, we believe that PRC-023-3 requirement R7 should only apply at 200kV and
above. Therefore, we request the SDT to change 4.2.3.1 to 'Transmission lines operated at 200kV and
above that are used…"
No
(1) We ask the SDT to clarify that 'nameplate MVA rating' means the 'generator nameplate MVA
rating'. Therefore we request that the SDT either add a statement "Unless otherwise stated,
'nameplate MVA rating' means the 'generator nameplate MVA rating' throughout Table 1", or insert
'generator' before 'nameplate MVA rating'.
No
(1) We request the SDT to add a multiple winding transformer example. We recommend that the SDT
include an example with equally rated CTGs connected to equally rated dual secondary transformer
windings stepping up to a single high voltage winding, because it is commonly used. (2) The MW
capability reported to the Transmission Planner changes by a very small amount from time to time. As
written we believe that this could trigger a significant amount of documentation. We request the SDT
to show in your example (s) how an increased margin would address such a small change (e.g. a 2%
increase from the originally documented value) before triggering such a review. (3) On page 2 of the
Guidelines and Technical Basis document, we ask the SDT to delete 'Generator Owner' from the last
sentence of Figure 2 caption.
Yes
Yes
(1) The generator overload protection exception on page 8 for “extremely inverse characteristics” (5th
bullet-dot) is a major improvement, but we believe that the term “full-load current” needs
clarification. We ask the SDT, is this current at 100% of the gross MW capability reported to the TP,
or the value determined from the generator nameplate MVA at rated voltage, or the base (no fans, no
oil circulation) rating of the GSU or the smallest of these? (2) We believe that Blackstart Resources
should be excluded because there is no technical basis for including them. On the contrary, it is more
important to assure Blackstart Resources are adequately protected and available for restoration in the
extremely unlikely event that a wide-area blackout occurs. Also, we believe that there is no evidence
that the tripping of a Blackstart Resources has contributed to widespread outages. In our experience,
these resources are below the 20MVA threshold and even if they were on-line and tripped their impact
to the BES are minimal. (3) In addition to our comments, we also agree with the SERC Protection &
Control Subcommittee (PCS) comments and include them by reference.
Thomas Foltz
American Electric Power
Does Not Apply
Does Not Apply
No
AEP believes that both documents would benefit from the inclusion of a simplified GO/TO interface
diagram showing the overlap and applicability of the two standards within the opening section of each
standard. Clarity needs to be provided to PRC-023-3 regarding the proper consideration of GO-owned
transmission line protection systems. It must be understood that for load responsive relays subject to
R7 and R8, the responsibility to perform loadability evaluations is on whoever is the owner of the
Protection System. Regarding PRC-023-3, it is unclear exactly what facilities are included in the term
“BES Generating Unit”. It is requested that this be clarified. AEP also requests clarification on the
voltage levels applicable to Regarding PRC-023-3 R7. Section 4.2.3.1 currently applies to
“transmission lines” which implies that all voltage levels would be subject to this requirement. It is
requested that this be revised to clarify exactly what voltage applies.

No
PRC-023-3 must be clear in stating that, if a Transmission or Distribution line used solely to export
energy directly from the GU has its own circuit breaker, then the existing R1 through R5 criteria
should be applied based on the rating of the line. PRC-023-3 appears to exclude relays directional
toward the Generating Unit. For example, if you attempt to evaluate loadability for two-terminal
345kV line to a windfarm, it appears to be applicable to both PRC-023-3 4.2.1 and 4.2.3. This would
make it difficult to determine what Transmission lines are subject to evaluation and which
requirement to apply, R1 or R7. Based on the current draft, it is not clear what criteria set to apply.
The criteria in Table 1 is based on Generator’s power while the criteria in Requirement 1 is based on
circuit ratings. It needs to be clarified which criteria set is to be applied. A second example is in a
situation when a loadability evaluation is needed for a two-terminal line that is definitely not
applicable to 4.2.1., but *is* applicable to 4.2.3. The intent of having two standards appears to be to
have the relays on the Generating Unit end owned by the GO, set according to criteria R1 in PRC-0251; and to have the relays on Generating Unit end owned by the TO, set according to criteria R7 in
PRC-023-3. In this example, there would appear to be no criteria required to set relays on the end
external to the Generating Unit, for relays owned by either the GO or TO. Clarification is needed to
define responsibility based on Protection System ownership as well as to clearly convey the
applicability of remote protection systems.
Yes
No
Regarding PRC-025-1: While AEP appreciates the factors considered by the drafting team when
developing the proposed implementation plan for PRC-025-1, the plan as proposed will not afford
adequate time for large Generator Owners to comply with the standards. AEP has 119 generating
units and 2 wind farms that are applicable to PRC-025-1. The resources needed to evaluate the
generating units for compliance with PRC-025-1 and PRC-023-3 will also be engaged in implementing
the new NERC standards PRC-019-1 and PRC-024-1. For these reasons, AEP believes a phased
implementation plan for PRC-025-1 is more appropriate. Such a plan would require entities to show
that a minimum percentage of their applicable relays are compliant within a specified time frame. For
example: * Entities shall demonstrate that 30% of their applicable load-responsive protective relays
are fully compliant with R1 within 48 months of the effective date of this standard. * Entities shall
demonstrate that 60% of their applicable load-responsive protective relays are fully compliant with R1
within 60 months of the effective date of this standard. * Entities shall demonstrate that 100% of
their applicable load-responsive protective relays are fully compliant with R1 within 72 months of the
effective date of this standard. Regarding PRC-023-3: The proposed revision could significantly impact
Transmission Owners. Additional research is being conducted within AEP Transmission to determine
the extent of that impact. It is possible that the proposed implementation plan would not provide
adequate time to achieve compliance with the standard if it is determined to impact a high volume of
facilities. Additional research will be needed before a recommendation be made on the extent the
additional time required. It is still unclear when TOs, GOs and DPs will be required to complete
loadability evaluations for any circuits below 200kV included by the Planning Coordinator per
Attachment B. It is understood that we will have 39 months to apply the initial list. There is confusion
however on whether or not the 39 months applies to new inclusions to the list. AEP requests that this
time frame be clarified and included in the standard, as it is information needed to maintain
compliance on an ongoing basis.
Yes
System fed auxiliary transformers whose loss would not result in an instantaneous generating unit
trip, and for which operators would have opportunity to reconfigure the plant auxiliary load before a
unit trip occurs, should be excluded from this standard. However, if the SDT intends the standard to
be applicable to all system fed auxiliary transformers, we recommend removing the text “…that trips
the generator either directly or via an interposing/lockout relay” from the standard. This statement is
similar to language that entities have used to exclude system fed auxiliary transformers that initiate a
process shutdown trip from the scope of other NERC PRC standards. During a disturbance in which
system voltage becomes depressed, the generator will respond by increasing excitation in an effort to
compensate for the voltage loss. This will result in the generator terminal voltage being greater than
the system voltage. For this reason, AEP recommends that settings for applicable relays installed on
the generator side of the GSU be based on a generator bus voltage of 1.0 per unit at the generator

terminals, rather than a generator bus voltage calculated from 0.85/0.95 per unit of the GSU highside nominal voltage.
Chris Mattson
Tacoma Power
Tacoma Power
Chris Mattson
Yes
Yes
Yes
Yes
Yes
Comments 1-4 below pertain to PRC-025-1. 1. Referring to Attachment 1, are phase fault detectors
used in current-based local breaker failure schemes excluded from PRC-025-1? 2. Referring to
Attachment 1, Footnote 3 still has the terms “no-load tap changers (NLTC)” and “on-load tap
changers (OLTC).” 3. Referring to page 22 of 68 of the redlined Guidelines and Technical Basis, the
first paragraph after “Generator Interconnection Facilities (Synchronous Generators) Phase Distance
Relays – Directional Toward Transmission System (21) (Options 14a and 14b),” change “…for these
relay…” to “…for these relays…” (There are also other instances of this issue.) 4. Referring to page 20
of 68 of the redlined Guidelines and Technical Basis, would the UATs shown in Figure 6 necessarily be
applicable to PRC-025-1? It seems that phase time overcurrent relays applied to UATs like these
might not “act to trip the generator directly or via lockout or auxiliary tripping relay.” Comments 5-8
below pertain to PRC-023-3. 5. Referring to Attachment C, why are only two of the bulleted
exceptions shown in PRC-025-1 Attachment 1 brought over? 6. Referring to page 12 of 13 of the
redlined Implementation Plan, change “…were added to address to situations…” to “…were added to
address situations…” 7. Referring to page 13 of 13 of the redlined Implementation Plan, last row in
the table, are references to R7 supposed to be references to R8? Additionally, change “…equally and
efficient…” to “…equally efficient…”
RoLynda Shumpert
South Carolina Electric and Gas
Self
RoLynda Shumpert
Yes
Yes
Yes
Yes
No
Rick Terrill
Luminant Generation
Luminant Generation
Rick Terrill

No
Luminant recommends the following: (1) Load responsive relays identified in PRC-025-1 and 023-3
connected on generator breaker(s) at the GSU high side and are primarily used for backup of failed
transmission line relaying shall use options in Attachment C (PRC-023-3) and Attachment 1 (PRC025-1). (2) Load responsive relays identified in PRC-023-3 and connected on the high side of the GSU
that are primarily used for transmission line protection shall use the existing criteria in PRC-023-2,
Requirements R1 through R6. The above recommendations can be done by adding diagrams in PRC023-3 and clarifying Figures 1, 2, and 3 in PRC-025-1.
No
Luminant disagrees that the criterion for setting load responsive relays is clear because of the bright
line is vague. Luminant recommends that each standard be clear in addressing the relay setting
criteria by its primary application.
No
Figures 1, 2, and 3 do not provide a sufficient bright line between the application of PRC-025-1 and
PRC-023-3 for setting criterion. Luminant recommends that additional information be added that
identifies that a load responsive relays located on the transmission line breaker at Bus A and are
primarily installed for transmission line protection use PRC-023-3 criterion Requirements R1 through
R6 (regardless of the number of generators or transmission lines connected to Bus A). Load
responsive relays located on the high side of the GSU and are primarily used for failed transmission
line protection should use PRC-023-3 (Attachment C) or PRC-025 (Table 1).
No
Luminant recommends that the phrase “where relay replacement is not required” and “where relay
replacement is required” add the word removal; i.e., “replacement or removal”.
No
David Gordon
Massachusetts Municipal Wholesale Electric Company
n/a
n/a
Agree
North American Generator Forum

Mark Stein
Tri-State G&T
Tri-State Generation and Transmission Assoc
Mark Stein

No
The generator overload protection exception added to Draft 3 for extremely inverse characteristics is
a major improvement, but the term “full-load current” needs clarification. Is this the current at
normal full-load turbine output and typical PF, or the value determined from the generator nameplate
MVA at rated voltage, or the base (no fans, no oil circulation) rating of the GSU?
Yes

1. UATs should be dropped from the standard. The Application Guidelines state that the reliability
objective of PRC-025 is to cover, “all load-responsive protective relays that are affected by increased
generator output in response to system disturbances,” but the relays of UATs are not in this category.
A disturbance on the HV system would not affect the real or reactive power draws of auxiliary loads,
and it was stated in the 12/13/2012 webinar that UAT relay trips are not known to have caused the
loss of any generation units during the northeast blackout of ’03. UATs are stated later in the
Application Guidelines to have been included to satisfy a FERC directive (Order No. 733, paragraph
104), but such a move nonetheless appears to be incorrect, particularly in light of NERC’s recent
emphasis on the cost justification of reliability standards. 2. PRC-025 should be revised to grandfather
existing major equipment, similar to the approach recently used for PRC-024. It may not always be
possible to develop PRC-025-conforming means of protection without replacing GSUs or UATs; and, in
the absence of any compensation to the owner, it would be inappropriate to outlaw equipment that
was acceptable under the rules in effect at the time it was installed. 3. The applicability of PRC-025
should exclude small gensets that are NERC-registered solely due to being black start-capable, the
tripping of which would not meaningfully affect the ability of the system to ride through Disturbances.
It would be best to allow such units to maintain their present loadability relay settings, if they are
consistent with a reasonable coordination study, rather than mandate upgrades that augment the
degree to which NERC requirements have already eliminated any economic rationale for having blackstart facilities. 4. Regarding in particular voltage-restrained overcurrent relays, this type of device is
notorious for not having a predictable operation time under fault conditions. If they did mis-operate in
the August 2003 blackout they should be changed-out rather than requiring that the settings be set
as high as specified in the draft standard.
PPL NERC Registered Affiliates
Brent Ingebrigtson
Yes
Yes
No
See Comments for Question #5
Yes
Yes
: The PPL NERC Registered Affiliates reiterate their concern in regards to the following comments. The
Application Guidelines state that the reliability objective of PRC-025 is to cover, “all load-responsive
protective relays that are affected by increased generator output in response to system disturbances.”
Unit Auxiliary Transformers (UAT’s) are not in this category and should therefore be excluded from
the Applicability of the Standard in Section 3.2.3. The point was made in the 5/15/13 webinar that a
decrease in HV system voltage would affect the plant MV voltage as well, causing a proportional
increase in current (at constant power draw by plant auxiliary loads) and thereby potentially tripping
UAT loadability relays. Reduction in frequency during disturbances will strongly reduce the power
draw of pumps and fans, however, so MV current may actually drop despite the HV voltage reduction
being experienced. This point of view is supported by the statement in the 12/13/2012 webinar that
UAT relay trips are not known to have caused the loss of any generation units during the northeast
blackout of ’03, so extending PRC-025 applicability to UATs provides only a hypothetical benefit that
has not been observed (or has in fact been disproved) in practice. The PPL NERC Registered Affiliates
again state that Facilities’ UATs in Section 3.2.3 do not belong in this standard as no technical
justification has been provided. An investigation and evaluation of the protection systems for unit
auxiliary transformers and the UAT’s lack of impact on generator loadability should be considered by
the SDT. A cost-benefit analysis for generator UATs should be performed to demonstrate that net
benefits will result from any such standard before it is proposed. Without such an analysis, the
standard may result in costs without a sufficient reliability benefit and may in some cases actually
lessen reliability (see item 5 below). 2.) The generator overload protection exception added to Draft 3
for “extremely inverse characteristics” (5th bull-dot) is a major improvement, but the term “full-load

current” needs clarification The PPL NERC Registered Affiliates suggest that the SDT state in the
Guidelines and Technical Basis that “full-load current” is understood to be the generator nameplate
MVA at rated voltage 3.) The overload protection exception added to Draft 3 for “extremely inverse
characteristics” should be applied for UAT’s as well if eliminating UAT’s in its entirety (per comment
#1 above) does not prove feasible. 4.) The PPL NERC Registered Affiliates reiterate their concern in
regards to the following comments. PRC-025 should be revised to grandfather existing major
equipment, similar to the approach recently used for PRC-024. It may not always be possible to
develop PRC-025-conforming means of protection without replacing GSUs or UATs; and, in the
absence of any compensation to the owner, it would be inappropriate to outlaw equipment that was
acceptable under the rules in effect at the time it was installed. 5.) The applicability of PRC-025
should exclude small gensets that are NERC-registered solely due to being black start-capable, the
tripping of which would not meaningfully affect the ability of the system to ride through Disturbances.
It would be best to allow such units to maintain their present loadability relay settings, if they are
consistent with a reasonable coordination study, rather than mandate upgrades that augment the
degree to which NERC requirements have already eliminated any economic rationale for having blackstart facilities. Given the numerous CIP standards in effect to afford protection to the critical BS
restoration facilities, it would be contradictory to impose a standard that could potentially increase
risk of damage to a BlackStart Generator by forcing the BS facility to ride through the disturbance. If
that disturbance is a precursor to a blackout, then having BS Resource unavailable to facilitate system
restoration would defeat the purpose of designating it as a Blackstart Resource. 6.) The PPL NERC
Registered Affiliates reiterate their concern in regards to the following comments. Regarding in
particular voltage-restrained overcurrent relays, this type of device is known for not having a
predictable operation time under fault conditions. If they did mis-operate in the August 2003 blackout
they should be changed-out rather than requiring that the settings be set as high as specified in the
draft standard. 7.) Deeming any and all violations of this standard to have a high violation risk factor
and a severe violation severity level seems overly harsh, given the compliance feasibility uncertainties
expressed above. 8.) The compliance uncertainties expressed above also promote the use of risk
based compliance approach rather than a zero tolerance policy. Other standards in development (CIP
V5 standards) no longer dictate a zero tolerance policy. This concept should be applied to the PRC025 standard to align with the direction NERC standard development is progressing.
North American Generator Forum Standards Review Team
Patrick Brown

No
See comments to question 5 below
Yes
1. UATs should be dropped from the standard. The Application Guidelines state that the reliability
objective of PRC-025 is to cover, “all load-responsive protective relays that are affected by increased
generator output in response to system disturbances,” but the relays of UATs are not in this category.
A disturbance on the HV system would not affect the real or reactive power draws of auxiliary loads,
and it was stated in the 12/13/2012 webinar that UAT relay trips are not known to have caused the
loss of any generation units during the northeast blackout of ’03. UATs are stated later in the
Application Guidelines to have been included to satisfy a FERC directive (Order No. 733, paragraph
104), but such a move nonetheless appears to be incorrect, particularly in light of NERC’s recent
emphasis on the cost justification of reliability standards. 2. The generator overload protection
exception added to Draft 3 for extremely inverse characteristics (5th bull-dot) is a major
improvement, but the term “full-load current” needs clarification. Is this the current at normal fullload turbine output and typical PF, or the value determined from the generator nameplate MVA at
rated voltage, or the base (no fans, no oil circulation) rating of the GSU? 3. The exception of
comment #2 above, which is presently limited to generator overloads, could be applied for UATs as
well if eliminating this equipment in its entirety (per comment #1 above) does not prove feasible. 4.
PRC-025 should be revised to grandfather existing major equipment, similar to the approach recently
used for PRC-024. It may not always be possible to develop PRC-025-conforming means of protection

without replacing GSUs or UATs; and, in the absence of any compensation to the owner, it would be
inappropriate to outlaw equipment that was acceptable under the rules in effect at the time it was
installed. 5. The applicability of PRC-025 should exclude small gensets that are NERC-registered solely
due to being black start-capable, the tripping of which would not meaningfully affect the ability of the
system to ride through Disturbances. It would be best to allow such units to maintain their present
loadability relay settings, if they are consistent with a reasonable coordination study, rather than
mandate upgrades that augment the degree to which NERC requirements have already eliminated any
economic rationale for having black-start facilities. 6. Regarding in particular voltage-restrained
overcurrent relays, this type of device is notorious for not having a predictable operation time under
fault conditions. If they did mis-operate in the August 2003 blackout they should be changed-out
rather than requiring that the settings be set as high as specified in the draft standard. 7. Deeming
any and all violations of this standard to have a high violation risk factor and a severe violation
severity level seems overly harsh, given the compliance feasibility uncertainties expressed above.
Michelle R. D'Antuono
Ingleside Cogeneration LP
Individual -- Ingleside Cogeneration LP
Michelle R. D'Antuono
No
Even though the language in both standards draws a technically accurate bright line, Ingleside
Cogeneration believes that the addition of the generator relay criteria to PRC-023-3 is confusing at
best. It appears that the issue has to do with the ownership of the relays. In some cases the DP
and/or the TO owns a load responsive relay that is protecting generation equipment. Conversely,
some GOs own load responsive relays that protect transmission equipment. If the concept of the two
standards is that PRC-023-3 applies to transmission-related relays and PRC-025-1 applies to
generation-related relays, than the owner of the relay is not a gating factor. This means that the
applicability table for both standards would include DPs, GOs, and TOs. There would be no repeated
criteria between the standards in this arrangement – and less confusing in our view.
Yes
Yes
No
Ingleside Cogeneration LP does not agree with the 100% compliance approach that the drafting team
has taken in regard to PRC-025-1. Although FERC Order 733 is cited multiple times as the reliability
need, there are real dollars that the industry will need to expend to analyze and replace load
responsive relays for generators of any size. We do not read Order 733 the same way – and FERC has
accepted exceptions for low-impact facilities in the past.
Yes
In the previous posting, the project team requested our estimated compliance costs and comments
on the RSAW. Both of these projects are components of risk-based compliance – which Ingleside
Cogeneration LP fully supports. However, it appears that these are not considerations at all in the
latest postings. We are not sure what has changed in the intellectual basis of risk-based compliance,
but it seems we have taken a step backwards. The rationale for far too many of the project team’s
consideration of comments was that FERC Order 733 mandated some action. Since FERC has been
generally supportive of the risk-based initiative, this type of response is inconsistent with their
position in our view.
Western Area Power Administration
Lloyd A. Linke
Yes
Yes

Recommend adding reference to Table 1 - Options 7, 8, 9, 10, 11, 12 – Relay Type back to options 1,
2, 3, 4, 5, 6 for applications on the generator side of the GSU. The language and reference used in
the Relay Type column for Options 1-6 added clarity and should be mirrored in Options 7-12.
Yes
No
Brenda Hampton
Luminant Energy Company LLC
Luminant
Brenda Hampton
Agree
Luminant Generation Company LLC
No
See Luminant Generation Company
No
See Luminant Generation Company
No
See Luminant Generation Company
No
See Luminant Generation Company
No

LLC comments.
LLC comments.
LLC comments.
LLC comments.

John Bee
Exelon and its affiliates
NA
NA

The Constellation Energy Nuclear Generation (CENG) NERC Registered Affiliates reiterate their
concern in regards to the following comments. The Application Guidelines state that the reliability
objective of PRC-025 is to cover, “all load-responsive protective relays that are affected by increased
generator output in response to system disturbances.” Section 3.2.3 of PRC-025-1 requires
clarification simply because the Unit Auxiliary Transformers (UAT’s) are not necessarily directly
connected to the generator, but there are indirect link to the generator operation. The UAT’s are ok to
be included to the applicability of this standard, but section 3.2.3 could use more detailed
explanation. Moreover, the webinar on 5/15/13 pointed out that a decrease in HV system voltage
would affect the plant MV voltage as well, causing a proportional increase in current (at constant
power draw by plant auxiliary loads) and thereby potentially tripping UAT loadability relays. Reduction
in frequency during disturbances will strongly reduce the power drawn of pumps and fans, however,
so MV current may actually drop despite the HV voltage reduction being experienced. This point of
view is supported by the statement in the 12/13/2012 webinar that UAT relay trips are not known to
have caused the loss of any generation units during the northeast blackout of ’03, so extending PRC025 applicability to UATs provides only a hypothetical benefit that has not been observed (or has in
fact been disproved) in practice. CENG state that Facilities, UAT’s in Section 3.2.3 is appropriate to
include it, but there need to be a specific explanation as to the affect of MW due to grid disturbance
affect the generator output. An investigation and evaluation of the protection systems for unit
auxiliary transformers and the UAT’s lack of impact on generator loadability should be considered.

Daniel Duff
Liberty Electric Power LLC
none
none
Agree
Generator Forum SDT, as submitted by Patrick Brown, Essential Power
No

Oliver Burke
Entergy Services, Inc. (Transmission)
Entergy Services, Inc. (Transmission Owner)
Oliver Burke
Yes
Yes
No
The Guidelines are still not clear about what to do with start-up transformers when used in lieu of the
UATs (Unit Auxiliary Transformer).
Yes
Yes
The implementation plan may be challenging to meet and an alternative implementation plan may
need to be provided based on the population of load-responsive protective relays determined affected
by this standard and the subset of which that will require replacement relays. Additional resources will
be required to (1) determine the population of load-responsive relays at each generating station, (2)
determine the settings of the existing load-responsive relays, (3) calculate load-responsive relay
settings per the reliability standard, (4) compare the existing load-responsive relay settings to the
calculated load-responsive relay settings to determine the population which are acceptable as-is, the
population that require a settings change, and the population that requires replacement, (5) schedule
the population of load-responsive relays for settings change, (6) order replacement load-responsive
relays for the population determined incapable of meeting the reliability standard and schedule relay
replacement. The resulting calculations and set-point datasheets will form the basis for the loadresponsive relay settings and evidence for meeting the standard’s requirements.
Dominion
Randi Heise
Yes
Dominion agrees that the addition of requirements in PRC-023-3, R7 and R8 strengthens the bright
line between the two standards. However, we do not agree with use of the term “Transmission’ in
4.2.3.1 as it is our position that it does not conform with the intent of the term as defined in the
NERC Glossary of Terms. We therefore suggest the sentence be revised to read “Lines that are used
solely to export energy directly from a BES generating unit or generating plant to the network.”
No
Dominion believes that the appropriate designation of “Real Power output” is the generator nameplate
rating however Dominion does recognize that the addition of “gross” prior to MW is an improvement

to the table wording.
Yes
Yes
Yes
PRC-025 -1 Requirement 1: remove the following words: “…while maintaining reliable fault
protection.” It is not possible for entities to measure or prove this statement. The wording, “while
maintaining reliable fault protection”, is also included in the Introduction section of PRC-025-1
Guidelines and Technical Basis. The inclusion “describes that the Generator Owner is to comply with
this standard while achieving its desired protection goals.” Dominion believes that the Generator
Owner understands the compliance obligation based upon the requirements of the standards and that
the inclusion of the referenced language should be excluded based on the inability of the entity to
measure or provide evidence of maintaining reliable fault protection. PRC-025-1: Redline - Page 6 of
18 Table of Compliance Elements; An indication of Lower VSL. Moderate VSL or High VSL needs to be
determined with regard to R1. Dominion disagrees with the “all or nothing” approach to VSLs. PRC023-3 Implementation plan; Redline Pages 3-6, R1-R6 the Requirement wording (in the Applicability
column) does not exactly match the Requirement wording in the standard. Dominion suggests
correcting the wording to match the Standard as written. PRC-025-1 @ figure 3 – Dominion does not
necessarily agree that these lines are part of networked transmission and therefore would not be
considered as generator interconnection Facilities. Dominion believes the designation of the lines
should be based on registration of the asset owner and will be providing supporting comments in
response to the FERC NOPR in docket # RM12-16-000.
Chantel Haswell
Public Service Enterprise Group
PSEG
Chantel Haswell
No
For UATs per PRC-025-1, that are energized from the system (as opposed to from the GSU), the SDT
seems to assumes that no TO or DP owns the load responsive relays for these UATs. Has that been
verified by the SDT?

Yes
The SDT needs to confirm that UATs that are energized from the system (not the GSU) at high-side
voltages that are below 100 kV are part of the BES before imposing standards on UAT load-responsive
relay settings.
Duke Energy
Michael Lowman
Yes
Yes
No
Examples of calculations are helpful. However, more details on the root of the calculations are
needed. Exclusively calculating values on a per unit basis would add more clarity.
No
Duke Energy schedules some of its generating units on a 24 month cycle for minor outages and a 96
month cycle for major outages. This would make the current Implementation Plan very expensive and

difficult to comply with if relay replacements are required. [Duke Energy suggests a 48 month and 96
month Implementation Plan. This would allow for the industry to use existing outage schedules,
keeping overall costs at a minimum.]
No
Bret Galbraith
Seminole Electric Cooperative Inc.
Seminole Electric Cooperative, Inc.
N/A

Yes
Seminole Electric reasons that the NERC SDT has not provided sufficient evidence to warrant a High
VRF and a Severe VSL for penalties associated with proposed Standard PRC-025-1.
Russ Schneider
Flathead Electric Cooperative
N/A
N/A
No
it is not clear to me how this would impact very small dispersed generators.

Yes
Do not support including Elements utilized in the aggregation of dispersed power producing resources.
This seems to have the potential to rope very small generators into significant compliance burdens for
very little reliability benefit.
Santee Cooper
Terry L. Blackwell

Yes
Unit Auxiliary Transformers (UATs) should be removed from this standard (Facilities Section 3.2.3).
The purpose of this standard is “To set load-responsive protective relays associated with generation
Facilities at a level to prevent unnecessary tripping of generators during a system disturbance for
conditions that do not pose a risk of damage.” The intent as stated in the Application Guidelines is to
pertain to relays that “are affected by increased generator output in response to system
disturbances.” UATs do not fit this criteria. Addressing generating plant unit auxiliary transformers
does not have to translate into creating a standard requirement for that equipment. An investigation
and evaluation of the protection system for unit auxiliary transformers should be considered by the
standard drafting team and deemed to be not related to generator loadability and fulfill the FERC
order to address the subject.
Robert Rhodes
Southwest Power Pool

N/A
N/A
Yes
Yes
Yes
Yes
Yes
For the sake of clarity, I would suggest adding the phrase ‘to the generator’ at the end of the Purpose
of PRC-025-1. This is implied in the existing language but it wouldn’t hurt to add this and specifically
indicate what damage you’re referring to. For consistency within the requirements and between the
requirement and corresponding measure in this situation, please add ‘Each’ at the beginning of
Requirement R8. This makes R8 consistent with the rest of the requirements and with Measure M8.
JEA
Tom McElhinney

No
While it has been demonstrated in the 2003 blackout that a small percentage of generating units did
trip off line prematurely due to conservative setting of generator protection systems, no evidence has
been provided that transformer tripping contributed to the cause of the generation outages. The sole
purpose as stated by the SDT for including transformers is a directive from FERC. We believe that
there should be some evidence as to the benefit of preforming protection modifications to
transformers and that they should not simply be included until a study can be performed to show the
cost benefit analysis and therefore recommend that transformers be excluded during this phase and
be incorporated into a phase III. If transformers are to be included, an exception should be provided
to allow the start-up transformer to be used to provide auxiliary power in case of failure of the
auxiliary transformer. BES reliability is better served by allowing this exception (which will occur very
infrequently) than to keep the generating unit off line for fear of being out of compliance with a
standard.
No
Considering that applying new settings and testing will require a major outage, we believe that 48
months is not a sufficient time frame for full implementation when existing equipment can be used
and relay replacement is not required. We recommend 72 months be allowed even in the case where
existing equipment can be used. It may take a year or more to perform the calculations and
evaluated equipment and then another 5 years for a major planned outage to occur.
Yes
We would like to see modifications to violation severity levels. While we recognize the SDT is following
NERC binary guidelines “pass/fail”, this needs to be improved. The idea that either they “applied” or
“did not apply” settings must result in a “severe” violation level does not match the reality that
missing 10 out of 20 poses a greater risk to the BES than 1 out of 100.
DTE Electric
Kent Kujala
Agree
No
Comments: The distinction is not clear between these two standards regarding generator owner

relays that look toward the transmission system. Perhaps specifying the application location of the
relay (CT and PT inputs) would help in clarifying the differences

No
Comments: Suggest that allowing 72 months to become 100% compliant for both 4a and 4b would
better align with the unmonitored protective relay maximum maintenance interval of 6 years specified
in PRC-005-2. In this way, relay setting changes or replacements could be accommodated during
normal scheduled relay maintenance. Also, 48 months could be difficult to achieve for a company with
a large generation fleet.
Bonneville Power Administration
Jamison Dye
No
The requirements for generator interconnection facilities in PRC-023-3 apply to Transmission Owner’s
(and Distribution Provider’s , and the requirements for generator interconnection facilities in PRC-0251 apply to Generation Owner’s. BPA believes that putting requirements for the generator
interconnection facilities in two separate standards and making the applicability of the standards
different is confusing and unnecessary. BPA recommends that all interconnection facilities, regardless
of ownership, should be covered within one standard to provide uniformity in the application of
settings for interconnection facilities.
No
Example: A 230kV line that is connected between a substation Terminal and a Generating station.
(Comment 1) This circuit fits under 4.2.3 of PRC-023-3, so it is subject to Requirement 7. The circuit
also fits under 4.2.1, so it is subject to Requirements R1 throughR5. BPA believes it should only be
subject to R1 throughR5 or R7, not both. (Comment 2) R7 requires that the load responsive relays be
set in accordance with PRC-023-3, Attachment C. BPA would like to point out that the phase distance
relays at the substation terminal looking toward the generation are not covered by Attachment C and
believes this creates a problem as it makes it impossible for these relays to be set in accordance with
Attachment C. The same problem also exists for relays at the terminal of the generator step up (GSU)
transformer looking toward the generation, recognizing that this is not a normal application. Based on
these issues, BPA believes Attachment C should address all relays, not just those looking towards the
Transmission system.
No
While the Guidelines and Technical Basis provides useful information, BPA is concerned that this
document will not be approved by FERC as part of the standard and thus the standard must be
capable of standing on its own. For this reason, BPA requests that clarification provided in the
Guidelines and Technical Basis document be included into the standard specifically in regards to
‘generator interconnection facilities’.
Yes
Yes
Comments: (1) The use of the term generation interconnection facility without an official definition of
the term is concerning to BPA. BPA believes that this term may have different meanings between
entities. For example, the entire Bulk Electric System (BES) together with all distribution systems
could be considered to be a generation interconnection facility because the purpose of the BES and
distribution systems is to interconnect generation to the end user (load). Only under the Guidelines
and Technical Basis is a description of what a generator interconnection facility found.BPA is
concerned with this approach as it does not give an official definition, and this document is not part of
the standard. Additionally, BPA believes the description of generator interconnection facility given in
the Guidelines and Technical Basis creates problems. The description provided is that the generation
interconnection facility consists of elements between the generator step up transformer (GSU) and
the interface with the portion of the BES where the Transmission Owner (TO) takes over the

ownership. In many cases the TO owns the line that connects to the generator step up (GSU)
transformer and there are no elements between the GSU and the TO. According to this description
there is no generation interconnection facility. Due to the ownership arrangements of transmission,
generation, and their interconnection facilities throughout the country are highly variable, BPA
believes it is not suitable to develop a definition of generation interconnection facilities based on
ownership. Such a definition may reflect the ownership arrangements within a particular region while
it does not take into account various other arrangements that may exist. BPA recommends for the
drafting team to provide a definition of generation interconnection facility that takes into account the
various ownership situations that may exist. (2) BPA believes the use of the word associated in the
purpose statement of PRC-025-1 as well as in Section 3.2 Facilities is too vague and recommends this
term be changed to “whose function is the protection of generation Facilities…” in the purpose
statement and Section 3.2 be rewritten to read “3.2 Facilities: The following Bulk Electric System
Elements, including those generating units and generating plants identified as Blackstart Resources in
the Transmission Operator's system restoration plan:”
Tennessee Valley Authority
Dennis Chastain
TVA electric generators segment agrees with comments submitted by the North American Generator
Forum (NAGF).
Yes
Yes
No

Yes
Is the intent of this standard to identify the lines in their normal configuration and not for contingency
events? For example, referring to Figure 3 from the Webinar, if a line is lost, causing the system
configuration to change to what is shown in Figure 1, does this mean that the configuration then is
considered to fall under R7?
ACES Standards Collaborators
Jason Marshall
No
There is definitely much clearer delineation between what is required in PRC-023 by the Transmission
Owner and Distribution Provider and in PRC-025 by the Generation Owner for generator step up
transformers, generators, auxiliary transformers and generator interconnection facilities. However,
PRC-023 still has other requirements that are applicable to Generators Owners that do not make
sense, create compliance risks and, thus, detract from reliability by distracting the Generator Owner
from value added reliability activities. For example, PRC-023 R1 is still applicable to the Generation
Owner and it should not be. A Generation Owner does not own transmission beyond the generator
interconnection facility. This is recognized in Project 2010-07 Generator Requirements at the
Transmission Interface and NERC’s work surrounding the GO/TO and GOP/TOP registration issues. If a
Generator Owner owned transmission beyond the generator interconnection facility, they would be
registered as a Transmission Owner. Thus, the Generator Owner will be stuck essentially going
through a registration exercise for every compliance activity to prove that the requirements do not
apply because they do not own transmission facilities. Other requirements in PRC-023 that require
removal of Generator Owner include R2, R3, R4, and R5. Until these removals occur, we will not be
able to support the standard.
Yes
The table is much clearer than in past versions. However, we do recommend one minor additional
change. The option numbers should be reset to 1 for every application and relay type combination
since they are truly options within those combinations. Otherwise, a reader may be believe they have
19 options and only have to pick one relay type and application to apply.

Yes
We agree with the 48-month and 72-month implementation plan for PRC-025 and R7 and R8 in PRC023. However, we believe the implementation plan for PRC-023 as a whole is confusing. Since PRC023-2 has a staggered implementation plan that is still has not fully been implemented, we
recommend laying out a graphical timeline or a Gantt chart that compares PRC-023-2 implementation
to that of PRC-023-3.
Yes
(1) We are not convinced that applicability of PRC-023 R7 and R8 to a Distribution Provider is
necessary. It would be unusual for a generator that meets BES definition criteria and compliance
registry criteria to be connected to a Distribution Provider. Both criteria require a single generator to
be 20 MVA or a plant site to be 75 MVA. From a practical perspective, this could actually be a
detriment to reliability by distracting the Distribution Provider from reliability activities because they
have to focus on documenting that they do not have any applicable generators connected. How does
including the Distribution Provider as an applicable entity benefit reliability? (2) The High VRFs for
PRC-023 R7 and R8 and PRC-25 R1 and R2 are inconsistent with established NERC criteria. In order to
meet the High criteria, a single violation of the requirement “could directly cause or contribute to bulk
electric instability, separation or a cascading sequence of failures.” A single failure to have a relay set
to avoid loadability concerns on a single generator could not lead to instability, separation or
cascading without violating other standards. For example, TOP-004-2 R2 already require N-1
operation so a single generator tripping due to relay loadability issues would require at least two
standards requirements violations. This cannot be viewed as “directly” causing. (3) We believe the
VSLs for PRC-023 R7 and R8 and PRC-25 R1 and R2 are written inconsistent FERC guideline 3 which
states that the VSL cannot change the requirement. The plain language of the requirements is written
in a plural format as though the requirement considers all relays are considered simultaneously. The
VSLs are written such that each relay that is not set appropriately is a separate violation. The VSLs, in
essence, change the requirements. For example, the Requirement for PRC-023 R7, states “shall set
their load responsive relays,” while the VSL essentially modifies the requirement to state “shall set
each load responsive relay.” We recommend modifying the VSL to be in better alignment with the
requirement. (4) The wording in the second sentence of the second paragraph in PRC-023 Attachment
C needs to be fixed. There seems to be an extra “Facilities.” (5) RRO is used throughout both
standards. It should be Regional Entity, as stated in NERC’s legal memorandum on the “Use of
‘Regional Reliability Organization’…” The memo states that in general, drafting teams can replace
“RRO” with “RE,” provided the functions being performed by the RE are related to their delegated
duties. Reliability Standards that refer to REs are legally binding on the REs by operation of Rule 100
of NERC’s Rules of Procedure and by the delegation agreements that NERC has entered into with each
RE. (6) Please strike “other entity as specified by the Regional Reliability Organization (RRO)” that is
used throughout Attachment C in PRC-023 and Attachment 1 in PRC-025. It creates compliance
uncertainty and provides the Regional Entity far too much discretion. If the purpose is an attempt to
document from other standards where the nameplate rating is communicating, we suggest that the
drafting team perform a search of the other standards and explicitly document the entities.
Otherwise, the Regional Entity, as the standard is worded, could simply decide to move the dates.
FERC has ordered NERC to remove regional discretion from standards development, such as the
revision of the BES definition. (7) We appreciate the relay elements that are identified for exclusion in
PRC-023 Attachment C. However, we believe that the exclusion should be identified explicitly in
Attachment A as well. Attachment A is referenced in applicability section. We are concerned since
attachment C is not referenced in the applicability section that exclusion of the relay elements could
be lost. (8) We disagree with the applicability of 3.2.5. We not understand how applicability to a
distribution collector system for dispersed generation benefits reliability. If a subset of generators in
the dispersed generation site trip, it will be a small amount of MWs lost that would not impact the
reliability of the Bulk Power System. We can understand inclusion of the main GSU for a large site but
not the individual collector elements.
Brett Holland
Kansas City Power and Light
same as individual info
same as individual info

No
We do not think that the Requirements added to the PRC-023-2 are any different than the
Requirements in PRC-025-1. We agree that the addition of PRC-025-1 will cause the removal of part 6
of Requirement 1 in PRC-023-2.
No
We do not think that the information that is shown in the Attachment is very easy to understand but
the additional information in the Guidelines and Technical Basis section helps to understand what the
table is requesting. Please add to the table the examples shown in the Guidelines and Technical Basis
or at a minimum refer to the location the example can be found in that document. This will assist in
the understanding of the table. In the Guidelines and Technical Basis the calculation the previous
value used for MW was based on the PF for Max Generation. In the new example the value of MW
used changed why did that value change?
Yes
Yes
Yes
Generators and Generator step up transformers are critical elements of the BES and have very long
lead times for replacement or major repair. However, the Transmission Relay load ability standard has
less stringent load ability requirements than the Generator load ability standard. Transmission lines
are allowed to trip at 150% of four hour rating or 115% of 15 minute rating. We do not understand
the newly added portion of the Exceptions of PRC-025-1 why is there only the option of a specific
curve type specified for the Generator. There is no exception available for the GSU or Aux
Transformers therefore the GSU and Aux transformers that would allow them to be set like large auto
transformers it is not our belief that these transformers should be required to be set with more
Stringent settings. We believe that these transformers should be set similar to the large auto
transformers.

Consideration of Comments

Project 2010-13.2 Phase 2 Relay Loadability: Generation
The Relay Loadability: Generation Drafting Team thanks all commenters who submitted comments on
PRC-025-1 and PRC-023-3. These standards were posted for a 30-day public comment period from April
25, 2013 through May 24, 2013. Stakeholders were asked to provide feedback on the standards and
associated documents through a special electronic comment form. There were 51 sets of comments,
including comments from approximately 166 different people from approximately 92 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process. If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary of changes (PRC-023-3)

The generator relay loadability standard drafting team (“SDT”) has revised the proposed the draft of
PRC-023-3 – Transmission Relay Loadability based on stakeholder comments received during its first
30-day formal posting. The following narrative is a summary of the significant improvements made to
the standard.
Standard (PRC-023-3)

The SDT, based on industry stakeholder comments, made substantive changes to the PRC-023-3
standard. The chief change was removing the previously proposed Requirement R7 and R8 which
applied to the generator interconnection Facility and generator step-up transformer applicable to
the Distribution Provider and Transmission Owner. With this change the SDT added the
Distribution Provider and Transmission Owner to the applicability of PRC-025-1 and removed the
applicability of those lines and transformers that are used exclusively to export energy directly
from a BES generating unit or generating plant to the network from PRC-023 to establish the
bright line between standards according to stakeholder comments.
Applicability
o Removed references to Requirements R7 and R8
1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

o Added the exception to sections 4.2.1.1, 4.2.2.1, and 4.2.2.2 to exclude lines and transformers
that are used exclusively to export energy directly from a BES generating unit or generating
plant to the network
o Removed the sections 4.2.3 and 4.2.4
Requirements
o Requirement R1, criterion 6 was removed to comport with the elimination of addressing loadresponsive protective relays on lines and transformers that are used exclusively to export
energy directly from a BES generating unit or generating plant to the network
Measures
o Removed the proposed Requirement R7
o Removed the proposed Requirement R8
Compliance
o Removed R7 and R8 references
Violation Severity Levels
o Removed R7 and R8
Attachment A
o Revised criterion 2.4 as “Note Used” since it is no longer needed
Attachment C
o Removed due to Requirements R7 and R8 being eliminated
Implementation Plan (PRC-023-3)

Updated to reflect the transition of PRC-023-3 Requirement R1, Criterion 6 to the proposed PRC025-1 criterion
VRF/VSL Justifications (PRC-023-3)

No change, not being provided for comment because the SDT is not making substantive changes to the
existing requirements. Only references to Requirement R1, criterion 6 were removed
Summary of changes (PRC-025-1)

The generator relay loadability standard drafting team (“SDT”) has revised the proposed draft of PRC025-1 – Generator Relay Loadability during its 30-day formal comment posting of the standard and
successive ballot which received 69.23% stakeholder approval. The following narrative is a summary of
the significant improvements made to the above standard.

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

2

Standard (PRC-025-1)

Purpose
o Minor change for clarity
Applicability
o Included the Distribution Provider and Transmission Owner
o Replaced “generator interconnection Facility” with “Elements that connect a GSU transformer
to the Transmission system that are used exclusively to export energy directly from a BES
generating unit or generating plant”
Requirement
o Added the Distribution Provider and Transmission Owner
Measures
o Added the Distribution Provider and Transmission Owner
Compliance
o Added the Distribution Provider and Transmission Owner
Violation Severity Levels
o Added the Distribution Provider and Transmission Owner
Attachment 1
o General text revisions and clarifications
o Removed the Regional Reliability Organization (RRO) references
o Added the following elements to Options 15, 16, and 18; “Phase overcurrent supervisory
elements (50) associated with current-based, communication-assisted schemes where the
scheme is capable of tripping for loss of communications – installed on the high-side of the
GSU transformer”
Implementation Plan (PRC-025-1)

The implementation period for applying settings to load-responsive protective relays that do not
require replacement or removal changed from 48 months to 60 months
The implementation period for applying settings to load-responsive protective relays that do
require replacement or removal changed from 72 months to 84 months
VRF/VSL Justifications (PRC-25-1)

Removed references to PRC-023-3.

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

3

Index to Questions, Comments, and Responses
_
1.

Do the changes to the proposed PRC-023-2 and PRC-025-1 (listed above) provide a bright line
between the two standards? If not, provide specific suggestions to improve or clarify the
performance between the standards. .............................................................................................. 15

2.

Does the Table 1: Relay Loadability Evaluation Criteria in both PRC-023-3 (Attachment C) and PRC025-1 (Attachment 1) clearly identify the criteria for setting load-responsive protective relays? If
not, provide specific detail that would improve the clarity of Table 1. ............................................ 33

3.

Does PRC-025-1, Guidelines and Technical Basis provide a clear understanding of the various
criteria, including the options (e.g., 1a, 1b, 1c, 2a, etc.) for setting load-responsive protective
relays? If not, provide specific detail that would improve the Guidelines and Technical Basis. ...... 49

4.

The drafting team developed an Implementation Plan for the added requirements of the proposed
PRC-023-3 that aligns with that proposed in PRC-025-1. Do you agree with the proposed
Implementation Plan for PRC-023-3 Requirements R7 and R8 and the proposed RC-025-1: a. 48months to apply load-responsive protective relay settings , where relay replacement is not
required, and b. 72-months to apply load-responsive protective relay settings, where relay
replacement is required? If not, provide an alternative implementation plan with specific rationale
for such an alternative period. .......................................................................................................... 61

5.

Do you have any other comments? If so, please provide suggested changes and rationale. .......... 69

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

4

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

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group
Pamela R. Hunter
No additional members listed.
2.

Group

Guy Zito

Additional Member

Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy Marketing

X

2

3

X

4

5

X

6

7

8

9

X

Northeast Power Coordinating Council
Additional Organization

Region Segment Selection

1.

Alan Adamson

New York States Reliability Council, LLC

NPCC

10

2.

Helen Lainis

Independent Electricity System Operator

NPCC

2

3.

Greg Campoli

New York Independent System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc.

NPCC

1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC

5

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

5

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8.

Kathleen Goodman

ISO - New England

NPCC

2

9.

Michael Jones

National Grid

NPCC

1

10.

David Kiguel

Hydro One Networks Inc.

NPCC

1

11.

Christina Koncz

PSEG Power LLC

NPCC

5

12.

Randy MacDonald

New Brunswick Power Transmission

NPCC

9

13.

Bruce Metruck

New York Power Authority

NPCC

6

14.

Silvia Parada Mitchell

NextEra Energy, LLC

NPCC

5

15.

Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

16.

Robert Pellegrini

The United Illuminating Company

NPCC

1

17.

Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC

1

18.

David Ramkalawan

Ontario Power Generation, Inc.

NPCC

5

19.

Brian Robinson

Utility Services

NPCC

8

20.

Brian Shanahan

National Grid

NPCC

1

21.

Wayne Sipperly

New York Power Authority

NPCC

5

22.

Donald Weaver

New Brunswick System Operator

NPCC

2

23.

Ben Wu

Orange and Rockland Utilities

NPCC

1

24.

Peter Yost

Consolidated Edison Co. of New York, Inc.

NPCC

3

3.

Group

David Thorne

Additional Member

Pepco Holdings Inc. & Afffiliates

Additional Organization

Carl Kinsley

Delmarva Power & Light Company

RFC

1, 3

2.

Alvin Depew

Pepco Holdings Inc.

RFC

1, 3

4.

Group

Additional Organization

Region Segment Selection

1.

Bill Smith

FE RBB Voter Seg 1

RFC

1

2.

Larry Raczkowski (proxy for Cindy Stewart) FE RBB Voter Seg 3

RFC

3

3.

Doug Hohlbaugh

FE RBB Voter Seg 4

RFC

4

4.

Ken Dresner

FE RBB Voter Seg 5

RFC

5

5.

Kevin Query

FE RBB Voter Seg 6

RFC

6

6.

Bill Duge

FE SME - Generation

RFC

5

7.

Brian Orians

FE SME - Generation

RFC

5

Additional Member

3

X

X

X

X

4

5

6

7

8

9

Region Segment Selection

1.

Doug Hohlbaugh

2

FirstEnergy

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

X

X

X

6

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8.

Rusty Loy

FE SME - Generation

RFC

5

9.

Jim Detweiler

FE SME - Transmission

RFC

1

10.

Rich Maxwell

FE SME - Transmission

RFC

1

5.

Group
Additional Member

Additional Organization

Region Segment Selection

1.

Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

2.

Chuck Lawrence

ATC

MRO

1

3.

Dan Inman

MPC

MRO

1, 3, 5, 6

4.

Dave Rudolf

BEPC

MRO

1, 3, 5, 6

5.

Kayleigh Wilkerson

LES

MRO

1, 3, 5, 6

6.

Jodi Jensen

WAPA

MRO

1, 6

7.

Joseph DePoorter

MGE

MRO

3, 4, 5, 6

8.

Ken Goldsmith

ALTW

MRO

4

9.

Lee Kittleson

OTP

MRO

1, 3, 4

10. Mahmood Safi

OPPD

MRO

1, 3, 5, 6

11. Marie Knox

MISO

MRO

2

12. Mike Brytowski

GRE

MRO

1, 3, 5, 6

13. Scott Bos

MPW

MRO

1, 3, 5, 6

14. Scott Nickels

RPU

MRO

4

15. Terry Harbour

MEC

MRO

1, 3, 5, 6

16. Tom Breene

WPS

MRO

3, 4, 5, 6

17. Tony Eddleman

NPPD

MRO

1, 3, 5

Russel Mountjoy

6.

Group

David Greene

Additional Member

Additional Organization

1.

Paul Nauert

Ameren

2.

Bridget Coffman

Santee Cooper

3.

Phil Winston

Southern Company

4.

Joel Masters

SCE&G

5.

David Greene

SERC RRO

MRO NERC Standards Review Forum

X

2

X

3

X

4

X

5

X

6

7

8

9

X

X

SERC Protection and Controls
Subcommittee
Region Segment Selection

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

10

7

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

7.

Group

Brent Ingebrigtson

Additional Member

PPL NERC Registered Affiliates
Additional Organization

X

Brenda Truhe

PPL Electric Utilities Corporation

RFC

1

2.

Annette Bannon

PPL Generation LLC on behalf of Supply NERC Registered Affiliates

RFC

5

WECC

5

Elizabeth Davis

PPL EnergyPlus, LLC

MRO

6

5.

NPCC

6

6.

SERC

6

7.

SPP

6

8.

RFC

6

9.

WECC

6

4.

8.

Group

Patrick Brown

Additional Member

North American Generator Forum
Standards Review Team

Additional Organization

Allen Schriver

NextEra Energy

5

2.

Steve Berger

PPL Susquehanna, LLC

5

3.

Joe Crispino

PSEG Fossil, LLC

5

4.

Pamela Dautel

IPR-GDF Suez Generation NA

5

5.

Dan Duff

Liberty Electric Power

5

6.

Mikhail Falkovich

PSEG

5

7.

Mike Hirst

Cogentrix Energy, LLC

5

8.

Gary Kruempel

MidAmerican Energy Company

5

9.

Katie Legates

American Electric Power

5

10.

Don Lock

PPL Generation, LLC

5

11.

Joe O'Brien

NIPSCO

5

12.

Dana Showalter

e.on

5

13.

William Shultz

Southern Company

5

14.

Mark Young

Tenaska, Inc.

5

9.

Group

Lloyd A. Linke

X

4

5

X

6

7

8

9

X

X

Region Segment Selection

1.

Additional Member

3

Region Segment Selection

1.
3.

2

Western Area Power Administration

Additional Organization

X

X

Region Segment Selection

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

8

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Upper Great Plains Region

Western Area Power Administrtion

MRO

1, 6

2.

Rocky Mountain Region

Western Area Power Administrtion

WECC

1, 6

3.

Desert Southwest Region

Western Area Power Administrtion

WECC

1, 6

4.

Sierra Nevada Region

Western Area Power Administrtion

WECC

1, 6

5.

CRSP Management Center

Western Area Power Administrtion

WECC

6

10.

Group

Randi Heise

Dominion

Additional Member

Additional Organization

Region Segment Selection

1.

Connie Lowe

Dominion

MRO

6

2.

Louis Slade

Dominion

RFC

5, 6

3.

Michael Garton

Dominion

NPCC

5, 6

4.

Michael Crowley

Dominion

SERC

1, 3

11.

Group
Additional Member

Michael Lowman
Additional Organization

Duke Energy

Doug Hils

RFC

1

2.

Lee Schuster

FRCC

3

3.

Dale Goodwine

SERC

5

4.

Greg Cecil

RFC

6

Group

Terry L. Blackwell

Santee Cooper

Additional Member

Additional Organization

Region Segment Selection

1.

Tom Abrams

Santee Cooper

SERC

1

2.

Bridget Coffman

Santee Cooper

SERC

1

3.

Rene' Free

Santee Cooper

SERC

1

4.

Paul Camilletti

Santee Cooper

SERC

5

13.

Group
Additional Member

Additional Organization

Region Segment Selection

1.

Ted Hobson

JEA

FRCC

1

2.

Garry Baker

JEA

FRCC

3

3.

John Babik

JEA

FRCC

5

14.

Group

Tom McElhinney

Kent Kujala

3

4

5

6

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

7

8

9

Region Segment Selection

1.

12.

2

JEA

DTE Electric

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

X

X

X

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization

Eizans

RFC

3, 4, 5

2.

Herring

NPCC

3, 4, 5

Group

Jamison Dye

Additional Member

Bonneville Power Administration

Additional Organization

Transmission Technical Services WECC 1

2. Stephen Enyeart

Customer Service Engineering

WECC 1

3. Jim Burns

Technical Operations

WECC 1

4. Sandra Takabayashi Hydro Projects

Group

Additional Organization

Tennessee Valley Authority

Daniel McNeely

SERC

1

2.

Ann Tankesley

SERC

1

3.

Lee Thomas

SERC

5

4.

Tom Vandervort

SERC

5

5.

Paul Palmer

SERC

5

6.

Annette Dudley

SERC

5

7.

DeWayne Scott

SERC

1

8.

Ian Grant

SERC

3

9.

David Thompson

SERC

5

10.

Marjorie Parsons

SERC

6

17.

Group

1.

Scott Brame

North Carolina Electric Membership Corporation

SERC

1, 3, 4, 5

2.

Megan Wagner

Sunflower Electric Power Corporation

SPP

1

3.

Chris Bradley

Big Rivers Electric Corporation

SERC

4.

Michael Brytowski

Great River Energy

MRO

1, 3, 5, 6

5.

Shari Heino

Brazos Electric Power Cooperative

ERCOT

1, 5

18.

Individual

Jason Marshall

X

X

X

X

X

X

X

X

7

8

9

X

ACES Standards Collaborators

Additional Organization

Ed Croft

6

Region Segment Selection

1.

Additional Member

5

WECC 5

Dennis Chastain

Additional Member

4

Region Segment Selection

1. Dean Bender

16.

3

Region Segment Selection

1.

15.

2

Region

Operational Compliance

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

Segment Selection

X

X

X

10

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

19.

Individual

Ryan Millard

PacifiCorp

20.

Individual

Texas Reliability Entity

Texas Reliability Entity

21.

Individual

Vladimir Stanisic

AESI Inc.

22.

Individual

John Yale

Chelan County PUD

23.

Individual

Barbara Kedrowski

Wisconsin Electric

24.

Individual

Clem Cassmeyer

Western Farmers Electric Cooperative

25.

Individual

Michael Mayer

Delmarva Power & Light Company

X

26.

Individual

NICOLE BUCKMAN

Atlantic City Electric Company

X

27.

Individual

Mark Yerger

Potomac Electric Power Company

X

28.

Individual

Jonathan Meyer

Idaho Power Company

X

Individual
30. Individual

Alice Ireland
Michael Falvo

Xcel Energy
Independent Electricity System Operator

X

31.

Individual

Wryan Feil

Northeast Utilities

X

32.

Individual

Nazra Gladu

Manitoba Hydro

X

33.

Individual

Anthony Jablonski

ReliabilityFirst

34.

Individual

David Jendras

Ameren

X

X

X

X

35.

Individual

Thomas Foltz

American Electric Power

X

X

X

X

36.

Individual

Chris Mattson

Tacoma Power

X

X

X

X

37.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

X

X

X

X

38.

Individual

Rick Terrill

Individual

David Gordon

Luminant Generation
Massachusetts Municipal Wholesale Electric
Company

40.

Individual

Mark Stein

Tri-State G&T

41.

Individual

Michelle R. D'Antuono

Ingleside Cogeneration LP

42.

Individual

Brenda Hampton

Luminant Energy Company LLC

29.

39.

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

X

X

X

7

8

9

10

X
X

X

X
X

X

X

X
X

X

X

X

X

X

X

X

X

X

X
X
X

X

X
X
X

11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

43.

Individual

John Bee

Exelon and its affiliates

44.

Individual

Daniel Duff

Liberty Electric Power LLC

45.

Individual

Oliver Burke

Entergy Services, Inc. (Transmission)

X

X

X

X

46.

Individual

Chantel Haswell

Public Service Enterprise Group

X

X

X

X

47.

Individual

Bret Galbraith

Seminole Electric Cooperative Inc.

X

X

X

X

48.

Individual

Russ Schneider

Flathead Electric Cooperative

X

X

49.

Individual

Robert Rhodes

Southwest Power Pool

50.

Individual

Brett Holland

Kansas City Power and Light

X

X

51.

Individual

Phil Waudby

Consumers Energy

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

X

X

7

8

9

X
X

X
X

X
X

X

X

12

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please
select "agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade
association, group, or committee, rather than the name of the individual submitter).

Summary Consideration: The drafting team thanks you for your support of other industry stakeholder comments. Approximately
ten commenters supported four other organization’s comments. These comments are too extensive to summarize here and are
summarized in the latter questions. Groups supported include Luminant Generation Company, LLC, North American Generator
Forum (i.e., Generator Forum SDT and NAGF), Pepco Holdings Inc. & Affiliates, and Western Farmers Electric Cooperative.

Organization

Agree

Supporting Comments of “Entity Name”

DTE Electric

Agree

North American Generator Forum

Wisconsin Electric

Agree

NAGF

Western Farmers Electric
Cooperative

Agree

Western Farmers Electric Cooperative

Delmarva Power & Light
Company

Agree

Pepco Holdings Inc. & Affiliates

Atlantic City Electric Company

Agree

Pepco Holdings Inc. and Affiliates

Potomac Electric Power
Company

Agree

Pepco Holdings Inc. and Affiliates

Massachusetts Municipal
Wholesale Electric Company

Agree

North American Generator Forum

Luminant Energy Company

Agree

Luminant Generation Company LLC

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

13

Organization

Agree

Supporting Comments of “Entity Name”

LLC
Liberty Electric Power LLC

Agree

Tennessee Valley Authority

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

Generator Forum SDT, as submitted by Patrick
Brown, Essential Power
TVA electric generators segment agrees with
comments submitted by the North American
Generator Forum (NAGF).

14

1.

Do the changes to the proposed PRC-023-2 and PRC-025-1 (listed above) provide a bright line between the two standards? If not,
provide specific suggestions to improve or clarify the performance between the standards.

Summary Consideration: Approximately three comments representing about eight entities agreed that the changes established a
bright line; however, the majority comments revealed that industry stakeholders did not agree with the drafting team’s proposed
changes to the draft PRC-023-3 standard by adding Requirements R7 and R8 to address those load-responsive protective relays that
would apply to the Distribution Provider and Transmission Owner. Among the previous additions include, Attachment C and Table 1
which contained the relay setting criteria as defined by the proposed PRC-025-1 standard applicable only to the generator. The
drafting team received approximately six comments supported by 35 stakeholders that either said they did not see how the bright
line was improved and the proposed Requirements R7 and R8, and Attachment C only added to confusion.
The drafting team agreed with the above comments and decided to integrate Transmission Owner and Distribution Provider into the
proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the
two standards. In doing so, the generator requirements subject to PRC-023-3 have been removed; however, will be enforceable until
the applicable entities become compliant with PRC-025-1, if settings need modifications. The drafting team notes that it is important
to recognize that the owner of load-responsive protective relays applied to generation-related Facilities will be in PRC-025-1 and
owner of load-responsive protective relays network-related Facilities in PRC-023-3 regardless of ownership of the Facilities.
The following discuss other minority comments by stakeholders. There was one comment supported by 11 entities asking the
drafting team to define “generation interconnection Facilities.” Although this was a minority comment, the drafting team decided
this had merit because the phrase was related to the work done under the NERC Project 2009-07 – Requirements at the Generation
Interface. Based on this project and industry’s understanding the generator interconnection Facility is generally owned by the
Generation Owner, the drafting team understood that when incorporating the Distribution Provider and Transmission Owner in PRC025-1 that the phrase would add confusion; therefore, the drafting team developed alternative phrasing that reads: “Elements that
connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit
or generating plant.”
Adding the Distribution Provider and Transmission Owner to the proposed PRC-025-1 standard addressed other minority comments.
One commenter noted that the Distribution Provider, Generator Owner, and Transmission Owner should be in both standards. This
was resolved addressing the majority comments. Two comments from individual entities noted that it appeared that both the
generator step-up (GSU) transformer and the unit auxiliary transformer (UAT) appeared to be in both standards. After review, the
drafting team noted that the GSU was applicable to the Distribution Provider and Transmission Owner in PRC-023-3 and the

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

15

Generator Owner in PRC-025-1 that own load-responsive protective relays on a GSU Facility; however, what was revealed was the
lack of coverage for a UAT that might be served from the Transmission System. This identification provided support in the drafting
team’s decision and response to comments to remove Requirements R7 and R8 from PRC-023-3 and add the Distribution Provider
and Transmission Owner to PRC-025-1 which included the UAT.
The final minority comments were related to applicability. One commenter believed that only Facilities 200 kV and above should
apply to the proposed Requirements R7 and R8 in PRC-023-3. The drafting team noted that it would create a gap in the Facilities that
would be covered in each standard; however, with the removal of the two proposed requirements this problem no longer exists.
About three comments supported by five entities ask for items that were either already in the provided Figures or as asked for more
clarity. The drafting team revised Figures 1, 2, 3, and 5 to add clarity.
An individual comment asked for clarity regarding “BES Generation Unit.” The drafting team noted that the proposed PRC-025-1
standard is driven by whether or not an individual generating unit or generating plant meets the Bulk Electric System (BES) definition
criteria (e.g., single units larger than 20 MVA or a site with an aggregate capacity of 75 MVA or greater). Once the unit or plant is
applicable, those Elements found the Applicability section 3.2, Facilities are to be addressed by the loadability criteria of the
standard. Last, one commenter asked how very small dispersed generators would be impacted. As mentioned in the previous
sentence, small generators are addressed by virtue of the BES definition.

Organization
Pepco Holdings Inc.
& Afffiliates

Yes or No

Question 1 Comment

No

1 ) The inclusion of Requirements R7 and R8 and the entire Table 1 from PRC-025-1
overly complicates PRC-023-3. In addition, inclusion of these Table 1 requirements
without the corresponding Guidelines and Technical Basis document produced for PRC025 makes the application of Table 1 in PRC-023 difficult, if not impossible. The intent
of the original PRC-023 was to apply to owners of load responsive relays (whether they
be TO’s or GO’s) that are applied on BES transmission circuits and BES power
transformers. The new PRC-025 standard should apply to owners of load responsive
relays (whether they be TO’s or GO’s) that are applied on BES generators, GSUs, UAT’s
and Generator Interconnection Facilities. In a good faith effort to provide a bright line
between the two standards, the new PRC-023-3 standard became overly complicated
and extremely confusing. It would seem that instead of adding PRC-025 requirements
to PRC-023, it would be much simpler to just add Transmission Owners to the

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

16

Organization

Yes or No

Question 1 Comment
Applicability Entities section of PRC-025. The Applicable Facilities section of each
standard should identify that any load responsive relay (whether they are owned by
GO’s or TO’s) installed on these types of facilities must comply with the respective
requirements of that standard. If this were done then the original PRC-023 could be
revised to exclude relays installed on generators, GSU’s, UAT’s and Generator
Interconnection Facilities, as they will be covered by PRC-025. PRC-023 would apply
solely to owners of load responsive relays (whether they be TO’s or GO’s) that are
applied on BES transmission circuits and BES power transformers.
2 ) It is unnecessary to remove Criterion 6 from PRC-023-3 as it represents an
acceptable alternative to the methods offered in PRC-025. When load responsive
relays are set on transmission line terminals connected to generation stations remote
from load in accordance with Criterion 6 of PRC-023 (230% of aggregate generation
nameplate capability) the resulting setting provides sufficient margin to accommodate
acceptable loadability. This criterion has been successfully used for years and has gone
through the full standards development process and been vetted as an acceptable
alternative. Consider the example calculation for Option 14a in PRC-025. From
Equation 112 the apparent primary impedance seen by the relay on the high side of the
GSU is 74.3 ohms primary at an angle of 52.77 degrees. Now assume the 230%
method from PRC-023 Criterion 6 was used instead. The new apparent power would
be 2.3 x (767.6 MW + j 475.6 MVAR) = 2.3 x 903 MVA =2076.9 MVA at an angle of 31.8
degrees. Using Equation 112 the apparent primary impedance would be 41.4 ohms at
31.8 degrees. From Equation 115 the setting required to satisfy Option 14a criteria
from PRC-025 would be 15.283 ohms sec = 76.42 ohms primary at 85 degrees. The
reach of this relay along the 31.8 degree load angle would be 76.42 x Cos (85 - 31.8) =
45.77 ohms primary. Since this is greater than the 41.4 ohm setting resulting from
Criterion 6 of PRC-023, the PRC-023 Criterion is slightly more conservative, requiring a
slightly smaller relay reach than Option 14a. As such, both methods should be
considered equally effective in ensuring relay loadability.

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

17

Organization

Yes or No

Question 1 Comment

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities
will be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership
of the Facilities. Change made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, the standard is being revised to exclude the lines
that are used exclusively to export energy directly from a BES generating unit or generating plant to the network from its
Applicability. Also, Requirement R1, Criterion 6 is proposed for removal from the standard, as it addresses those Facilities being
excluded from the Applicability. Change made.
The drafting team thanks you for your comment and notes that it considered this same concern in past meetings and concluded
that the Mega-Watt (MW) value reported to the Transmission Planner was the most practical approach for a basis in
determining the required setting(s). The Generator Owner has flexibility in using a more restrictive setting, which would be the
case of using the generator name plate. In option 1, for example, the requirement is to use 100% of the reported MW and 150%
of the nameplate MW to arrive at the Mvar component of the complex power. The impedance element must be set less than
the calculated impedance derived from 115% of the complex power, which is using criteria (1) and (2). The standard allows the
applicable entities the flexibility to account for variable changes in the reported MW value and select a setting that best suits
their specific operating history or expectation. No change made.
Using the reported MW value accounts for environmental conditions that impact the operation of generation units and those
units which operate at a level lower than their nameplate rating. This more closely achieves a loadability setting corresponding
with the expected performance of the generator during field-forcing. No change made.
FirstEnergy

No

FirstEnergy (FE) appreciates the attempt to develop a bright-line method but feel the
approach taken is over complicating the standards. FE believes that the changes made
to PRC-023 with the inclusion of requirements R7 and R8 and the associated
Attachment C cause unnecessary confusion. FE proposes that the team remove R7, R8
and Attachment C from PRC-023 and retain a modified version of PRC-023, R1 item 6.
Further, as supported in our comments below, we encourage the team to limit the
applicability of PRC-023 to the TO and DP and the applicability of PRC-025 to the GO. FE

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

18

Organization

Yes or No

Question 1 Comment
believes it is imperative for NERC to develop its standards in a consistent approach in
regard to terminology that is deemed “transmission” and those deemed “generation”.
We are concerned that the proposed changes to PRC-023 and PRC-025 overly
complicate what most in industry already understand to be “transmission” and
“generation” facilities. For example, NERC recently proposed errata changes to PRC004 and PRC-005 to clarify that for a GO the requirements of those standards extend
not only to protection systems associated with the generating facility or station itself,
but also to any protection systems associated with the generator interconnection
facility. It’s difficult to understand why PRC-004 and PRC-005 seem to have clear TO
and GO boundaries when it comes to reporting relay misoperations and performing
relay maintenance, yet when ensuring relay loadability requirements are met things all
of a sudden become much more complicated. To date, generation interconnection
facility(ies) as used in NERC standards are generator owner assets, “generator lead”,
operated at transmission voltage levels. However, if the generator lead happens to be
owned by a transmission owner, then it’s understood simply to be a transmission line
or transmission facility. The two relay loadability standards should maintain this same
simplicity and PRC-023 should apply only to TO/DP and PRC-025 to the GO.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement R7
and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, the
standard is being revised to exclude the lines that are used exclusively to export energy
directly from a BES generating unit or generating plant to the network from its
Applicability. Also, Requirement R1, Criterion 6 is proposed for removal from the
standard, as it addresses those Facilities being excluded from the Applicability. Change

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

19

Organization

Yes or No

Question 1 Comment
made.
The Generator Owner must be retained in the proposed PRC-023-3 standard to address
those cases where the Generator Owner owns transmission load-responsive protective
relays. Generator Owners may own transmission load-responsive protective relays
applied on network transmission lines. For both standards, it is the ownership of the
relays that drives the Applicability, not the ownership of the assets (e.g., GSU,
transmission line). No change made.
We suggest that the team take this opportunity to introduce a formally defined NERC
Glossary Term for generator interconnection facility. During the recent webinar the
team spent a fair amount of time indicating that when evaluating a generator
interconnection facility(ies) as shown in Figure 1 and Figure 2 that it essentially comes
down to the relay owner when determining which standard (PRC-023 or PRC-025) is
applicable. The team indicated that if the GO owns the relay for line breaker(s) at Bus
A then PRC-025 applies, but if the DP/TO owns the relay then PRC-023 applies. The
team further described that the GO was left in PRC-023 to handle a situation where
they may own relaying for line breaker(s) on networked transmission lines as shown in
Figure 3.
Response: The drafting team has replaced this term with "Elements that connect a GSU
to the Transmission system and are used exclusively to export energy directly from a
BES generating unit or generating plant." Change made.
The team also cited they retained the GO for this situation to avoid a potential
“registration tension”. The perceived need for the GO in standard PRC-023 calls into
question the facility rating for the network transmission line as established under FAC008-3. NERC standards must maintain consistent philosophies in terminology
throughout all standards and cover the most common system configurations. Any
unique situations will need to be dealt with on a case by case basis between asset
owners. Additionally, NERC drafting teams should not be writing standards to cover

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

20

Organization

Yes or No

Question 1 Comment
one-off configurations simply to address potential entity registration concerns.
Response: The drafting team found that these conditions exist throughout North
America in varying degrees due to industry deregulation and other factors. The drafting
team is defining criteria such that similar Facilities will be subject to similar
requirements regardless of Facility ownership as it relates to the NERC functional
model. No change made.
While FE strongly objects to the use of R7, R8 and Attachment C in PRC-023, if the team
does not agree with our proposal to remove the GO completely from PRC-023 then as
an alternate approach we support comments filed by Pepco Holdings, Inc. - PHI which
suggesting adding the TO/DP to PRC-025 and removing R7, R8 and Attachment C from
PRC-023. Either approach (FE’s or PHI’s) requires retaining item 6 of R1 in PRC-023.
Response: In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
the standard is being revised to exclude the lines that are used exclusively to export
energy directly from a BES generating unit or generating plant to the network from its
Applicability. Also, Requirement R1, Criterion 6 is proposed for removal from the
standard, as it addresses those Facilities being excluded from the Applicability. Change
made.
The Generator Owner must be retained in the proposed PRC-023-3 standard to address
those cases where the Generator Owner owns transmission load-responsive protective
relays. Generator Owners may own transmission load-responsive protective relays
applied on network transmission lines. For both standards, it is the ownership of the
relays that drives the Applicability, not the ownership of the assets (e.g., GSU,
transmission line). No change made.
The criterion in PRC-025-1 is technically similar, but more precise than PRC-023-2
Requirement R1, Criterion 6; therefore, Criterion 6 must be removed. The drafting
team acknowledges that entities that previously implemented Criterion 6 may find that
changes are necessary; if so, the PRC-025-1 Implementation Plan would apply. Change

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

21

Organization

Yes or No

Question 1 Comment
made.
In summary, for PRC-023, FE proposes the following:
1.) Remove the Generator Owner applicability
2.) Remove Requirements 7 and 8 since they will be included in PRC-025
3.) Remove Attachment C
4.) Change Requirement 1 Criteria #6 to read as follows:
“Set transmission line relays applied on transmission lines connected to generation
stations remote to load directional towards the generator so they do not operate at or
below 115% of the rating of the generator as calculated according to applicable NERC
standards.”
Although not our preferred option, we also recommend the team considered the
suggestion by PHI that would add the TO as an applicable entity to PRC-025 while also
removing PRC-023 R7, R8 and Attachment C.
Response: Thank you for adding the summary. Please see the above responses.

Response: The drafting team thanks you for your comments; please see the above responses.
DTE Electric

No

Comments: The distinction is not clear between these two standards regarding
generator owner relays that look toward the transmission system. Perhaps specifying
the application location of the relay (CT and PT inputs) would help in clarifying the
differences

Response: The drafting team thanks you for your comment and notes that load-responsive protective relays applied on
"Elements that connect a GSU to the Transmission system and are used exclusively to export energy directly from a BES
generating unit or generating plant" (which replaces the previously-used term, “generator interconnection Facility”) are covered
under the proposed PRC-025-1 standard. Load-responsive protective relays applied on network transmission lines are covered
under the proposed PRC-023-3 standard. Please refer to the revised Figures 1, 2, and 3 in the proposed PRC-025-1 Guidelines

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

22

Organization

Yes or No

Question 1 Comment

and Technical Basis for further information on applications. Change made.
Bonneville Power
Administration

No

The requirements for generator interconnection facilities in PRC-023-3 apply to
Transmission Owner’s (and Distribution Provider’s, and the requirements for generator
interconnection facilities in PRC-025-1 apply to Generation Owner’s. BPA believes that
putting requirements for the generator interconnection facilities in two separate
standards and making the applicability of the standards different is confusing and
unnecessary. BPA recommends that all interconnection facilities, regardless of
ownership, should be covered within one standard to provide uniformity in the
application of settings for interconnection facilities.

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities
will be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership
of the Facilities. Change made.
ACES Standards
Collaborators

No

There is definitely much clearer delineation between what is required in PRC-023 by
the Transmission Owner and Distribution Provider and in PRC-025 by the Generation
Owner for generator step up transformers, generators, auxiliary transformers and
generator interconnection facilities.
However, PRC-023 still has other requirements that are applicable to Generators
Owners that do not make sense, create compliance risks and, thus, detract from
reliability by distracting the Generator Owner from value added reliability activities.
For example, PRC-023 R1 is still applicable to the Generation Owner and it should not
be. A Generation Owner does not own transmission beyond the generator
interconnection facility. This is recognized in Project 2010-07 Generator Requirements
at the Transmission Interface and NERC’s work surrounding the GO/TO and GOP/TOP
registration issues. If a Generator Owner owned transmission beyond the generator

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

23

Organization

Yes or No

Question 1 Comment
interconnection facility, they would be registered as a Transmission Owner. Thus, the
Generator Owner will be stuck essentially going through a registration exercise for
every compliance activity to prove that the requirements do not apply because they do
not own transmission facilities. Other requirements in PRC-023 that require removal
of Generator Owner include R2, R3, R4, and R5. Until these removals occur, we will not
be able to support the standard.

Response: The drafting team thanks you for your comment and notes that the Generator Owner must be retained in the
proposed PRC-023-3 standard to address those cases where the Generator Owner owns transmission load-responsive protective
relays. Generator Owners may own transmission load-responsive protective relays applied on network transmission lines. For
both standards, it is the ownership of the relays that drives the Applicability, not the ownership of the assets (e.g., GSU,
transmission line). No change made.
Chelan County PUD

No

It seems that GSU and UAT would be subject to PRC-023 and PRC-025. It would be
cleaner if one standard applied to GSU and UAT and the other to the transmission
circuits.

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities
will be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership
of the Facilities. Change made.
With the changes, the GSU and UAT now apply to one standard, the proposed PRC-025-1.
Western Farmers
Electric Cooperative

No

See comments to question 5

Response: The drafting team thanks you for your comments; please see responses in question 5.

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Ameren

Yes or No
No

Question 1 Comment
(1) For consistency, we believe that PRC-023-3 requirement R7 should only apply at
200kV and above. Therefore, we request the SDT to change 4.2.3.1 to 'Transmission
lines operated at 200kV and above that are used..."

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities
will be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership
of the Facilities. Change made.
Although PRC-023 has a provision for addressing Facilities less than 200 kV for transmission network load-responsive protective
relays; however, the drafting team is addressing generation Facilities such that the PRC-025 standard will be consistent with the
definition of the Bulk Electric System (BES). Including those generation Facilities that are less than 200 kV addresses all BES
generation which may be important during an event where field-forcing increases the need for a reasonable level of loadability.
No change made.
American Electric
Power

No

AEP believes that both documents would benefit from the inclusion of a simplified
GO/TO interface diagram showing the overlap and applicability of the two standards
within the opening section of each standard. Clarity needs to be provided to PRC-0233 regarding the proper consideration of GO-owned transmission line protection
systems. It must be understood that for load responsive relays subject to R7 and R8,
the responsibility to perform loadability evaluations is on whoever is the owner of the
Protection System.
Regarding PRC-023-3, it is unclear exactly what facilities are included in the term “BES
Generating Unit”. It is requested that this be clarified. AEP also requests clarification
on the voltage levels applicable to Regarding PRC-023-3 R7. Section 4.2.3.1 currently
applies to “transmission lines” which implies that all voltage levels would be subject to
this requirement. It is requested that this be revised to clarify exactly what voltage
applies.

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Organization

Yes or No

Question 1 Comment

Response: The drafting team thanks you for your comment and notes that the Generator Owner must be retained in the
proposed PRC-023-3 standard to address those cases where the Generator Owner owns transmission load-responsive protective
relays. Generator Owners may own transmission load-responsive protective relays applied on network transmission lines. For
both standards, it is the ownership of the relays that drives the Applicability, not the ownership of the assets (e.g., GSU,
transmission line). No change made.
The circumstance is the same as the current definition of Bulk Electric System that apply to the those individual generating units
20 MVA and larger or 75 MVA in aggregate on a site, including those Blackstart generating units identified in the Transmission
Operator’s system restoration plan. No change made.
The drafting team notes that load-responsive protective relays applied on "Elements that connect a GSU to the Transmission
system and are used exclusively to export energy directly from a BES generating unit or generating plant" (which replaces the
previously-used term, “generator interconnection Facility”) are covered under the proposed PRC-025-1 standard. Loadresponsive protective relays applied on network transmission lines are covered under the proposed PRC-023-3 standard. Please
refer to the revised Figures 1, 2, and 3 in the proposed PRC-025-1 Guidelines and Technical Basis for further information on
applications. Change made.
With the removal of Requirements R7 and R8, the Applicability section 4.2.3.1 is no longer relevant. Change made.
Luminant Generation

No

Luminant recommends the following:
(1) Load responsive relays identified in PRC-025-1 and 023-3 connected on generator
breaker(s) at the GSU high side and are primarily used for backup of failed transmission
line relaying shall use options in Attachment C (PRC-023-3) and Attachment 1 (PRC025-1).
(2) Load responsive relays identified in PRC-023-3 and connected on the high side of
the GSU that are primarily used for transmission line protection shall use the existing
criteria in PRC-023-2, Requirements R1 through R6. The above recommendations can
be done by adding diagrams in PRC-023-3 and clarifying Figures 1, 2, and 3 in PRC-0251.

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Organization

Yes or No

Question 1 Comment

Response: The drafting team thanks you for your comment and notes that load-responsive protective relays applied on
"Elements that connect a GSU to the Transmission system and are used exclusively to export energy directly from a BES
generating unit or generating plant" (which replaces the previously-used term, “generator interconnection Facility”) are covered
under the proposed PRC-025-1 standard. Load-responsive protective relays applied on network transmission lines are covered
under the proposed PRC-023-3 standard. Please refer to Figures 1, 2, and 3 in the proposed PRC-025-1 Guidelines and Technical
Basis for further information on applications. No change made.
Ingleside
Cogeneration LP

No

Even though the language in both standards draws a technically accurate bright line,
Ingleside Cogeneration believes that the addition of the generator relay criteria to PRC023-3 is confusing at best. It appears that the issue has to do with the ownership of
the relays. In some cases the DP and/or the TO owns a load responsive relay that is
protecting generation equipment. Conversely, some GOs own load responsive relays
that protect transmission equipment.
If the concept of the two standards is that PRC-023-3 applies to transmission-related
relays and PRC-025-1 applies to generation-related relays, than the owner of the relay
is not a gating factor. This means that the applicability table for both standards would
include DPs, GOs, and TOs. There would be no repeated criteria between the
standards in this arrangement - and less confusing in our view.

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities
will be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership
of the Facilities. Change made.
Luminant Energy
Company LLC

No

See Luminant Generation Company LLC comments.

Response: The drafting team thanks you for your comments; please see the response(s) for Luminant Generation Company LLC.

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Public Service
Enterprise Group

Yes or No
No

Question 1 Comment
For UATs per PRC-025-1, that are energized from the system (as opposed to from the
GSU), the SDT seems to assumes that no TO or DP owns the load responsive relays for
these UATs. Has that been verified by the SDT?

Response: The drafting team thanks you for your comment and notes it has not independently verified this particular scenario;
however, with the proposed revisions, the Distribution Provider and Transmission Owner that own load-responsive protective
relays regarding the unit auxiliary transformer (UAT) are now applicable under the proposed PRC-025-1 standard.
The drafting team has decided to integrate Transmission Owner and Distribution Provider into the proposed PRC-025-1, rather
than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two standards. The owner
of load-responsive protective relays applied to generation-related Facilities will be in PRC-025 and owner of load-responsive
protective relays network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
Flathead Electric
Cooperative

No

it is not clear to me how this would impact very small dispersed generators.

Response: The drafting thanks you for your comments. This would not have any impact on very small dispersed generators
unless they form aggregated generation at a single interconnection point as delineated in the latest approved BES definition
(i.e., those individual generating units 20 MVA and larger or 75 MVA in aggregate on a site). No change made.
Kansas City Power
and Light

No

We do not think that the Requirements added to the PRC-023-2 are any different than
the Requirements in PRC-025-1. We agree that the addition of PRC-025-1 will cause
the removal of part 6 of Requirement 1 in PRC-023-2.

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities
will be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership
of the Facilities. Change made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, the standard is being revised to exclude the lines

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Organization

Yes or No

Question 1 Comment

that are used exclusively to export energy directly from a BES generating unit or generating plant to the network from its
Applicability. Also, Requirement R1, Criterion 6 is proposed for removal from the standard, as it addresses those Facilities being
excluded from the Applicability. Change made.
Liberty Electric
Power LLC

No

Dominion

Yes

Dominion agrees that the addition of requirements in PRC-023-3, R7 and R8
strengthens the bright line between the two standards. However, we do not agree with
use of the term “Transmission’ in 4.2.3.1 as it is our position that it does not conform
with the intent of the term as defined in the NERC Glossary of Terms. We therefore
suggest the sentence be revised to read “Lines that are used solely to export energy
directly from a BES generating unit or generating plant to the network.”

Response: The drafting team thanks you for your comment and notes that the comment above is no longer relevant because:
The drafting team has decided to integrate Transmission Owner and Distribution Provider into the proposed PRC-025-1, rather
than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two standards. The owner
of load-responsive protective relays applied to generation-related Facilities will be in PRC-025 and owner of load-responsive
protective relays network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
Operational
Compliance

Yes

Content is good. However - the two standards should refer to EXACTLY the same table
of Relay Loadability Evaluation Criteria with EXACTLY the SAME OPTION #s for each
Relay Type/Application. The table could stand on its own and each record be labeled
with PRC-025 and/or PRC-023 applicability (new column(s)).

Response: The drafting team thanks you for your comment and notes that the comment above is no longer relevant because:
The drafting team has decided to integrate Transmission Owner and Distribution Provider into the proposed PRC-025-1, rather
than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two standards. The owner
of load-responsive protective relays applied to generation-related Facilities will be in PRC-025 and owner of load-responsive

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Organization

Yes or No

Question 1 Comment

protective relays network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation;
Southern Company
Generation and
Energy Marketing

Yes

MRO NERC Standards
Review Forum

Yes

SERC Protection and
Controls
Subcommittee

Yes

PPL NERC Registered
Affiliates

Yes

Western Area Power
Administration

Yes

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Organization

Yes or No

Duke Energy

Yes

Tennessee Valley
Authority

Yes

PacifiCorp

Yes

AESI Inc.

Yes

Idaho Power
Company

Yes

Xcel Energy

Yes

Independent
Electricity System
Operator

Yes

Northeast Utilities

Yes

Manitoba Hydro

Yes

ReliabilityFirst

Yes

Tacoma Power

Yes

South Carolina
Electric and Gas

Yes

Entergy Services, Inc.

Yes

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
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Question 1 Comment

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Organization

Yes or No

Question 1 Comment

(Transmission)
Southwest Power
Pool

Yes

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2.

Does the Table 1: Relay Loadability Evaluation Criteria in both PRC-023-3 (Attachment C) and PRC-025-1 (Attachment 1)
clearly identify the criteria for setting load-responsive protective relays? If not, provide specific detail that would improve
the clarity of Table 1.

Summary Consideration: In whole, the comments presented in this question were minority comments. Approximately, two
comments representing 16 stakeholders reiterated that Requirements R7 and R8 should be removed from PRC-023. The drafting
team removed the requirements and instead added the Distribution Provider and Transmission Owner to PRC-025 to avoid a gap or
overlap in compliance as addresses in the above question.
The most notable minority comment by the SERC Protection Control Subcommittee identified key elements missing in PRC-025-1
that were addressed in PRC-023. That item was “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 drafting team agreed and added these elements to the proposed PRC-025-1,
Attachment 1, Table 1.
Also, one entity objected to the use of “Regional Reliability Organization (RRO)” within the two standards due to being outdated.
The drafting team re-evaluated the use of the term which was added to address an implementation gap between the MOD-025-2
standard that is pending regulatory approval and the subsequent approval of PRC-025-1. The problem stemmed from the applicable
entities possibly not having an official reported value to the Transmission Planner pursuant to MOD-025-1 which could pose a
compliance risk. To resolve this issue, the drafting team agreed with support of comments and regulatory staff to increase the PRC025-1 standard Implementation Plan by one year. This would ensure that MOD-025-1 would be fully in effect (about 6 months) upon
the date which entities must demonstrate compliance with PRC-025-1.
One entity suggested to the drafting team to provide references within the PRC-025-1, Table to improve the clarity. Previously, the
drafting team in Table 1 and in options addressing the generator-side relay of the GSU, referenced the high-side option to help direct
readers to the corresponding option. The drafting team clarified the high-side options with the same reference back to the
generator-side relay of the GSU. The remaining comments, all minority comments, related to technical issues the drafting team
worked through in earlier postings. Items such as using the generator nameplate, seasonal variation, or items addressed more fully
in other questions in this comment report.

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Pepco Holdings Inc. &
Afffiliates

Yes or No

Question 2 Comment

No

For the PRC-025 standard the inclusion of Table 1 along with the Figures and Example
Calculations in the Guidelines and Technical Basis document clearly identifies the
proposed setting criteria. However, the inclusion of Table 1 in PRC-023 overly
complicates the scope of PRC-023, and without inclusion of the corresponding
Guidelines and Technical Basis document makes application of Table 1 criteria difficult.
We feel strongly that all references to load responsive relays applied on generators,
GSU’s, UAT’s and Generation Interconnection Facilities (including Table 1 and
Requirements R7 and R8) should be eliminated from PRC-023 as they are already
adequately covered in PRC-025. Transmission Owners that own load responsive relays
on those types of facilities should be included as an Applicable Entity under PRC-025.
(See comments submitted for Question 1).

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities will
be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership of
the Facilities. Change made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, Attachment C and its Table 1 have been eliminated.
Change made.
FirstEnergy

No

As stated above (Question 1) FE does not support the inclusion of Attachment C in
PRC-023. See question 1 for more information. From a technical standpoint, we
support Table 1 of PRC-025.

Response: The drafting team thanks you for your comments; please see the above responses in question 1.
SERC Protection and
Controls Subcommittee

No

There is a discrepancy between the relay functions listed in PRC-023-3 Attachment A
and those identified in PRC-023-3 Attachment C Table 1 and PRC-025-1 Attachment 1
Table 1. PRC-023-3 Attachment A includes under 1.6, “Phase overcurrent supervisory

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Yes or No

Question 2 Comment
elements (i.e., phase fault detectors) associated with current-based, communicationassisted schemes (i.e., pilot wire, phase comparison, and line current differential)
where the scheme is capable of tripping for loss of communications.” These schemes
are not accounted for in the Table 1 of either proposed standard. Given these
schemes are required to meet loadability criteria on transmission lines not meeting
the “generator interconnection facility” designation (i.e. networked lines), the
exclusion of the schemes from generator loadability criteria creates confusion.
Loadability criteria should be included for “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” in Table 1 of both PRC-023-3
and PRC-025-1.

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities will
be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership of
the Facilities. Change made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, Attachment C and its Table 1 have been eliminated.
Change made.
The drafting team thanks you for your comments and agrees with this suggestion and has modified the proposed PRC-025-1
standard in Attachment 1, Table 1, Options 15a, 15b, 16a, 16b, 18 and 19 to address this condition. Change made.
Dominion

No

Dominion believes that the appropriate designation of “Real Power output” is the
generator nameplate rating however Dominion does recognize that the addition of
“gross” prior to MW is an improvement to the table wording.

Response: The drafting team thanks you for your comment and notes that it considered this same concern in past meetings and
concluded that the Mega-Watt (MW) value reported to the Transmission Planner was the most practical approach for a basis in

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Organization

Yes or No

Question 2 Comment

determining the required setting(s). The Generator Owner has flexibility in using a more restrictive setting, which would be the
case of using the generator name plate. In option 1, for example, the requirement is to use 100% of the reported MW and 150%
of the nameplate MW to arrive at the Mvar component of the complex power. The impedance element must be set less than the
calculated impedance derived from 115% of the complex power, which is using criteria (1) and (2). The standard allows the
applicable entities the flexibility to account for variable changes in the reported MW value and select a setting that best suits
their specific operating history or expectation. No change made.
Using the reported MW value accounts for environmental conditions that impact the operation of generation units and those
units which operate at a level lower than their nameplate rating. This more closely achieves a loadability setting corresponding
with the expected performance of the generator during field-forcing. No change made.
Bonneville Power
Administration

No

Example: A 230kV line that is connected between a substation Terminal and a
Generating station.
(Comment 1)
This circuit fits under 4.2.3 of PRC-023-3, so it is subject to Requirement 7. The circuit
also fits under 4.2.1, so it is subject to Requirements R1 throughR5. BPA believes it
should only be subject to R1 through R5 or R7, not both.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement
R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, the
Applicability – 4.2, Circuits now provide the exclusion “except lines that are used
exclusively to export energy directly from a BES generating unit or generating plant to
the network.” Criterion 6 in Requirement R1 remains unused. Change made.

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Organization

Yes or No

Question 2 Comment
In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
Attachment C and its Table 1 have been eliminated. Change made.
(Comment 2)
R7 requires that the load responsive relays be set in accordance with PRC-023-3,
Attachment C. BPA would like to point out that the phase distance relays at the
substation terminal looking toward the generation are not covered by Attachment C
and believes this creates a problem as it makes it impossible for these relays to be set
in accordance with Attachment C. The same problem also exists for relays at the
terminal of the generator step up (GSU) transformer looking toward the generation,
recognizing that this is not a normal application. Based on these issues, BPA believes
Attachment C should address all relays, not just those looking towards the
Transmission system.
Response: The drafting team added text to note that load-responsive protective relays
directional toward the generator are not included. Also, the drafting team notes that
the load-responsive protective relays directional toward the generator are not
challenged by the loadability concerns for the stressed system conditions being
addressed by the proposed PRC-025-1 standard; thus, criteria for these relays are not
necessary. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Texas Reliability Entity

No

(1) Texas RE objects to the use of the term Regional Reliability Organization (RRO) in
Table 1. RRO is an obsolete term that NERC had been trying to purge from the
standards, and we are somewhat alarmed to see it used in a new place in the
standards. While we recognize that RRO is defined in the Glossary, it is not in the
functional model and, at least in our region, it does not identify any entity and it is
ambiguous. We urge you to replace the term RRO with an entity type from the
functional model, or to write a description of what is intended without using the term

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Organization

Yes or No

Question 2 Comment
"RRO".
Response: The reference to “…or other entity as specified by the Regional Reliability
Organization (RRO)” has been removed from the standard. Change made.
(2) Regarding the “Transformers” section on page 7 and footnote 3 on page 10,
consider whether it is appropriate to use the “nameplate impedance at the nominal
GSU turns ratio” in all instances. In some cases, it is more appropriate to use the
calculated (i.e. with compensation) impedance that reflects the lowest value based on
the de-energized tap and LTC tap positions for this purpose.
Response: The drafting team notes that the tap impedance for older transformers may
not be available for all tap positions; therefore, the drafting team is requiring the use
of the nominal impedance. If entities wish to employ the actual tap impedance used or
the most conservative tap impedance available, they may reflect that in the relay
settings selected provided that the setting achieves the relay pick up setting criteria in
Table 1. No change made.
(3) For Options 1a, 2a, and 7a, consider using 0.9 per unit instead of 0.95 per unit,
because typical disturbance (post-contingency) voltage criterion is 0.9 p.u.
Response: The 0.95 per unit voltage specified in these options reflect the approximate
generator bus voltage at a 0.85 per unit system voltage with a representative
transformer impedance of 12 percent during field-forcing. No change made.
(4) Consider clarifying that the Real Power output criteria should be based on the
[highest seasonal] MW rating for the applicable unit. There can be significant seasonal
variations in MW capabilities for some units. We don’t expect pickup settings to be
changed from season to season, so an appropriate year-round setting should be
determined and applied.
Response: Seasonal variations are discussed in Attachment 1: Relay Settings under the
heading “Generators.” The section states: “If different seasonal capabilities are
reported, the maximum capability shall be used for the purposes of this standard.” No

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Yes or No

Question 2 Comment
change made.
(5) Some transmission systems have steady state stability limits that encroach into the
generator capability limits. Consider adding exclusion criteria for these types of
scenarios.
Response: The drafting team notes that the generator is providing VARs to the system
during field-forcing anticipated by the standard. The steady-state stability limit
encroachment occurs only in the leading VAR scenario. This issue is being addressed by
the NERC Board of Trustees adopted PRC-019-1 standard. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
AESI Inc.

No

The team is commended for an extensive effort to provide high level of detail through
numerous relay setting examples summarized in Table 1 and elaborated in the
document
PRC_025_1_Guidlines_and_Technical_Basis_Draft_3_2013_04_24_Redline.pdf.
Nonetheless, the following points may need further attention:
1. The settings derived by simulations versus the settings derived by manual
calculations are noticeably different, the latter being repeatedly much more
conservative (e.g. 8c: 6.6 A pu versus 8a: 9.5 A pu), exposing generators to a higher
risk of overloading. It would be expected that the results of manual calculations and
simulations would yield closer values, at least for most of typical configurations. It
appears that underlying assumptions used in the calculations and simulations may
need to be fine-tuned. For example, is it realistic to have field forcing producing 1.5 pu
MVAR output and at the same time generator bus voltage at 0.95 pu.
Response: The drafting team notes that “manual” calculations, in some cases, may be
significantly more conservative than simulation results. However, the criteria specified
by Options 1a, etc. reflect behavior observed for some generators in actual events and
simulations. Therefore, the specified criteria are appropriate for non-simulation based

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Yes or No

Question 2 Comment
analysis. No change made.
2. The settings derived by manual calculations are such the generators are exposed to
a higher risk of overloading:
Example 1a - 21 protection would operate only when unit loading exceeds
approx. 280% (at rated power factor).
Example 2a - 51V protection pickup is set at equivalent of approx. 170%
loading.
Taking into account that overcurrent relays actually react when current exceeds 1.5
pickup setting, equivalent loading on the unit would have to exceed 250% before
timing is initiated. Depending on the relay characteristic, time delay can be significant.
Response: The drafting team acknowledges that fault protective relaying may not
provide adequate thermal overload protection; an exclusion is provided in the
proposed PRC-025-1 standard for protection that is focused exclusively on overload
protection. No change made.
3. C37.102 states that acceptable settings for 21 function are 150% to 200% (at rated
power factor). These values should guide the requirements of this standard.
Response: The drafting team notes that for some generators a setting of 150% to
200% of the generator MVA rating at its rated power factor is insufficient and is
moving beyond the general application guidance expressed in C37.102 so that loadresponsive protective relays allow generators to support the system during stressed
conditions to the extent possible. The drafting team also notes that while C37.102
provides general guidance on the reach for phase fault backup protection, it also
provides insight regarding situations in which voltage regulator action could cause an
incorrect trip. Similar to information in the Guidelines and Technical Basis for PRC-0251, C37.102 notes that consideration should be given to reducing the reach of the relay
and/or coordinating the tripping time delay with the time delays of the protective

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Yes or No

Question 2 Comment
devices in the voltage regulator. It also recommends that the setting of these relays be
evaluated between the generator protection engineers and the system protection
engineers to optimize coordination while still protecting the turbine generator, and
that stability studies may be needed to help determine a set point to optimize
protection and coordination. No change made.
4. The Table specifies pickup setting criteria. It remains unclear when are the relays
allowed to trip.
Response: The drafting team notes that the impedance elements are allowed to trip at
less than the pickup setting criteria and overcurrent elements are allowed to trip at
greater than the pickup setting criteria. Timing considerations such as relay
coordination are not addressed by this standard. No change made.
5. Examples 7a, b, c, seem to be duplication of 1a, b, c.
Response: Refer to Figure 4 in the Guidelines and Technical Basis. Option 1 relays are
located on the generator and Option 7 relays are on the low-side terminals of the
generator step-up (GSU) transformer. No change made.
6. The following comment from the Guidelines document is not clear:======Options
7a and 10, Table 1 - Bus Voltage, calls for a 1.0 per unit of the high-side nominal
voltage for generator busvoltage, ***however due to the presence synchronous
generator 0.95 per unit bus voltage will be used as (Vgen)***?:==========
Response: The description prior to Equation 76 in the Guidelines and Technical Basis
has been clarified as to why the 0.95 voltage is being used in the case of mixed
synchronous and asynchronous generation. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Xcel Energy

No

For 51 relay that is installed on the high side of GSU, we suggest it should be an
acceptable option if the 51 relay setting meets R1 Criteria 11.

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Yes or No

Question 2 Comment

Response: The drafting team thanks you for your comments notes that the criteria expressed in PRC-023-3, R1 Criterion 11,
represents steady-state conditions for transmission transformers and does not represent the conditions that the GSU would see
during field-forcing conditions. No change made.
Ameren

No

(1) We ask the SDT to clarify that 'nameplate MVA rating' means the 'generator
nameplate MVA rating'. Therefore we request that the SDT either add a statement
"Unless otherwise stated, 'nameplate MVA rating' means the 'generator nameplate
MVA rating' throughout Table 1", or insert 'generator' before 'nameplate MVA rating'.

Response: The drafting team thanks you for your comments and has added “generator” immediately prior to the applicable uses
of “nameplate MVA rating” in Table 1. Change made.
American Electric
Power

No

PRC-023-3 must be clear in stating that, if a Transmission or Distribution line used
solely to export energy directly from the GU has its own circuit breaker, then the
existing R1 through R5 criteria should be applied based on the rating of the line.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement
R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, the
Applicability – 4.2, Circuits now provide the exclusion “except lines that are used
exclusively to export energy directly from a BES generating unit or generating plant to
the network.” Criterion 6 in Requirement R1 remains unused. Change made.
PRC-023-3 appears to exclude relays directional toward the Generating Unit. For
example, if you attempt to evaluate loadability for two-terminal 345kV line to a

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Question 2 Comment
windfarm, it appears to be applicable to both PRC-023-3 4.2.1 and 4.2.3. This would
make it difficult to determine what Transmission lines are subject to evaluation and
which requirement to apply, R1 or R7. Based on the current draft, it is not clear what
criteria set to apply. The criteria in Table 1 is based on Generator’s power while the
criteria in Requirement 1 is based on circuit ratings. It needs to be clarified which
criteria set is to be applied.
A second example is in a situation when a loadability evaluation is needed for a twoterminal line that is definitely not applicable to 4.2.1., but *is* applicable to 4.2.3. The
intent of having two standards appears to be to have the relays on the Generating Unit
end owned by the GO, set according to criteria R1 in PRC-025-1; and to have the relays
on Generating Unit end owned by the TO, set according to criteria R7 in PRC-023-3. In
this example, there would appear to be no criteria required to set relays on the end
external to the Generating Unit, for relays owned by either the GO or TO. Clarification
is needed to define responsibility based on Protection System ownership as well as to
clearly convey the applicability of remote protection systems.
Response: The drafting team added text to note that load-responsive protective relays
directional toward the generator are not included. Also, the drafting team notes that
the load-responsive protective relays directional toward the generator are not
challenged by the loadability concerns for the stressed system conditions being
addressed by the proposed PRC-025-1 standard; thus, criteria for these relays are not
necessary. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Luminant Generation

No

Luminant disagrees that the criterion for setting load responsive relays is clear because
of the bright line is vague. Luminant recommends that each standard be clear in
addressing the relay setting criteria by its primary application.

Response: The drafting team thanks you for your comment and notes that load-responsive protective relays applied on

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Question 2 Comment

"Elements that connect a GSU to the Transmission system and are used exclusively to export energy directly from a BES
generating unit or generating plant" (which replaces the previously-used term, “generator interconnection Facility”) are covered
under the proposed PRC-025-1 standard. Load-responsive protective relays applied on network transmission lines are covered
under the proposed PRC-023-3 standard. Please refer to the revised Figures 1, 2, and 3 in the proposed PRC-025-1 Guidelines and
Technical Basis for further information on applications. Change made.
Luminant Energy
Company LLC

No

See Luminant Generation Company LLC comments.

Response: The drafting team thanks you for your comments; please see the response(s) for Luminant Generation Company LLC.
Kansas City Power and
Light

No

We do not think that the information that is shown in the Attachment is very easy to
understand but the additional information in the Guidelines and Technical Basis
section helps to understand what the table is requesting.
Please add to the table the examples shown in the Guidelines and Technical Basis or at
a minimum refer to the location the example can be found in that document. This will
assist in the understanding of the table.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement
R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
Attachment C and its Table 1 have been eliminated. Change made.
In the Guidelines and Technical Basis the calculation the previous value used for MW
was based on the PF for Max Generation. In the new example the value of MW used

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Question 2 Comment
changed why did that value change?
Response: In the previous draft of the calculations, the Preported and the calculated P
happened to be the same value and caused confusion. Because of the identical values,
the drafting team decided to use a different value for P reported so that the values would
not be confused. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Western Area Power
Administration

Yes

Recommend adding reference to Table 1 - Options 7, 8, 9, 10, 11, 12 - Relay Type back
to options 1, 2, 3, 4, 5, 6 for applications on the generator side of the GSU. The
language and reference used in the Relay Type column for Options 1-6 added clarity
and should be mirrored in Options 7-12.

Response: The drafting team thanks you for your comment and agrees that where the generator-side options refer to the highside options, that the high-side options should also refer to the generator-side options. Change made.
ACES Standards
Collaborators

Yes

The table is much clearer than in past versions. However, we do recommend one
minor additional change. The option numbers should be reset to 1 for every
application and relay type combination since they are truly options within those
combinations. Otherwise, a reader may be believe they have 19 options and only have
to pick one relay type and application to apply.

Response: The drafting team thanks you for your comment and suggestion; however, the drafting team asserts the use of
sequential numbering is more beneficial and avoids confusion when referring to an option. No change made.
Operational
Compliance

Yes

But...see comments for Question #1.

Response: The drafting team thanks you for your comments; please see the above responses for question 1.

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Manitoba Hydro

Yes or No
Yes

Question 2 Comment
(1) Manitoba Hydro suggests eliminating Table 1 from one of the standards and
referencing it in the other standard, since both PRC-023-3 and PRC-025-1 are already
very lengthy standards.

Response: The drafting team thanks you for your comment and has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays applied to generation-related Facilities will
be in PRC-025 and owner of load-responsive protective relays network-related Facilities in PRC-023 regardless of ownership of
the Facilities. Change made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, Attachment C and its Table 1 have been eliminated.
Change made.
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation; Southern
Company Generation
and Energy Marketing

Yes

MRO NERC Standards
Review Forum

Yes

PPL NERC Registered

Yes

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Question 2 Comment

Affiliates
Duke Energy

Yes

Tennessee Valley
Authority

Yes

PacifiCorp

Yes

Chelan County PUD

Yes

Idaho Power Company

Yes

Independent Electricity
System Operator

Yes

Northeast Utilities

Yes

ReliabilityFirst

Yes

Tacoma Power

Yes

South Carolina Electric
and Gas

Yes

Ingleside Cogeneration
LP

Yes

Entergy Services, Inc.
(Transmission)

Yes

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Southwest Power Pool

Yes or No

Question 2 Comment

Yes

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3.

Does PRC-025-1, Guidelines and Technical Basis provide a clear understanding of the various criteria, including the options
(e.g., 1a, 1b, 1c, 2a, etc.) for setting load-responsive protective relays? If not, provide specific detail that would improve the
Guidelines and Technical Basis.

Summary Consideration: There were three significant comments in this question. One comment representing about five
stakeholders suggested defining “generator interconnection Facility.” The drafting team addressed this in several comments and the
summary can be found in the summary to question 1. Second, the same comment revealed minor errors in a Figure, calculation, and
within the Guidelines and Technical Basis. The drafting team corrected these errors and made clarifications. Also, this commenter
suggested performing calculations in per unit; however, the team disagreed that the current method was adequate.
Other minority single comments relate to issues the drafting team has worked through in earlier postings of the standard. They
include the basis why transformers are being addressed, applicability of the UAT used only during startup, multi-winding example
calculation, changes in the reported Real Power out to the Transmission Planner (e.g. seasonal variations), appending the Guidelines
and Technical Basis back to the standard, and request for clarity in the examples.

Organization
Pepco Holdings Inc. &
Afffiliates

Yes or No

Question 3 Comment

No

1 ) The new term “Generator Interconnection Facilities” is not defined in the NERC
Glossary of terms, nor is it defined in the body of the standard. It is defined in the
Guidelines and Technical Basis document; however, we feel this term needs to be
defined within the body of the standard itself. Perhaps a footnote similar to that used
to define Unit Auxiliary Transformers would be appropriate. We would suggest the
same definition used in the Guidelines and Technical Basis document be inserted:
“Generator interconnection Facility(ies) consists of Elements between the generator
step-up transformer and the interface with the portion of the bulk Electric System
(BES) where Transmission Owners take over the ownership.”
Response: The drafting team has replaced this term with "Elements that connect a
GSU to the Transmission system and are used exclusively to export energy directly
from a BES generating unit or generating plant." Change made.

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Question 3 Comment
2 ) In Figures 4 and 5 the CT’s supplying the 21, 51V-R and 51V-C relays connected to
the generator(s) look like they are connected to the generator neutral. To make it
clear that they are supplied from CT’s connected in the phase leads, a phase to neutral
transition symbol (ref Fig 7.4 in IEEE C37.102) should be used to indicate the CTs are
located above the neutral connection point.
Response: Figures 4 and 5 have been modified to address this concern. Change made.
3 ) In Figure 5 there is a 51 relay shown connected to the 22kV bus leads supplying the
generator on the left hand side of the drawing. This 51 relay is not reverenced, or
used, in any of the options and therefore should be removed from the drawing.
Response: Figure 5 and Table 1, Option 5 has been revised to address this concern.
Change made.
4 ) Options 14a, 14b, 15a, 15b, 16a and 16b all use an MVAR value equal to 120% of
the aggregate generation MW value, instead of the 150% value used when the relays
are located on the generator side of the GSU transformer. Presumably this is to
account for the I squared Xt MVAR loss consumed in the GSU transformer. However,
there is no mention of this fact in the Guidelines and Technical Basis document. To
avoid confusion as to why different MVAR criteria are used, supporting technical
justification / explanation should be offered in the document.
Response: The assumption is correct. Discussion has been added to the Guidelines and
Technical Basis. Change made.
5 ) The example calculations for Options 4 and 10 are combined as a single identical
set of calculations. This calculation is appropriate for Option 10 but not for Option 4.
Referring to Figure 5, the 21 relays for Option 4 are shown connected to each
individual generator. Also the 20MVAR static compensation source is connected
upstream of each generator relay. As such, the 21 relay on each individual generator
(Option 4) will only see the MW and MVAR flows from a single generator, not the
aggregate of all the generation plus the 20MAR reactive source. A separate

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Question 3 Comment
calculation for Option 4 should be developed. For that Option 4 case the single
generator apparent power (assuming three generators of equal size) would be 102/3 =
34 MW and 63.2/3 = 21 MVAR, which is 40 MVA for each generator.
Response: Figure 5 in the Guidelines and Technical Basis has been modified to account
for this discrepancy and the calculation example for Option 4 and 10 have been
separated. Change made.
6 ) The example calculations for Option 5 appear to be incorrect. Again referring to
Figure 5, the 51V-R relays for Option 5 are shown connected to each individual
generator. Also the 20MVAR static compensation source is connected upstream of
each generator relay. As such, the 51V-R relay on each individual generator (Option 5)
will only see the MW and MVAR flows from a single generator, not the aggregate of all
the generation plus the 20MAR reactive source. As such the 51V-R relay should be set
to 130% of the maximum MVA rating of that individual generator. Again assuming
three units of equal size, each generator would be rated 40MVA and therefore the
51V-R relay should be set to not operate below 1.3 x 40 = 52 MVA
Response: The calculation for Option 5 in the Guidelines and Technical Basis has been
corrected to reflect a single asynchronous generation unit and not the aggregate.
Change made.
7 ) The example calculations for Options 7a, 10, 8a, 9a, 11, and 12 illustrate a mixture
of synchronous and asynchronous generators. However, there is no corresponding
one-line drawing which corresponds to these examples. Because of this, it is difficult
visualize the topology of this arrangement and where the corresponding relays would
be located. If the SDT wishes to provide an example calculation where there is a mix
of synchronous and asynchronous generation then we would suggest an additional
figure be added (Figure 6) which would illustrate this type of connection.
Response: Figure 5 and the calculations for Option 10 in the Guidelines and Technical
Basis has been modified and corrected to reflect a mixture of synchronous and

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Yes or No

Question 3 Comment
asynchronous generators (Equations 71-93). Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
PPL NERC Registered
Affiliates

No

See Comments for Question #5

Response: The drafting team thanks you for your comments; please see the responses for question 5.
North American
Generator Forum
Standards Review
Team

No

See comments to question 5 below

Response: The drafting team thanks you for your comments; please see the responses for question 5.
Duke Energy

No

Examples of calculations are helpful. However, more details on the root of the
calculations are needed. Exclusively calculating values on a per unit basis would add
more clarity.

Response: The drafting team thanks you for your comment and asserts the basis for the calculations are addressed in the
Guidelines and Technical Basis narrative. The drafting team also notes that Generator Owners may perform calculations in per
unit or in actual values. The examples are provided in actual values. No change made.
JEA

No

While it has been demonstrated in the 2003 blackout that a small percentage of
generating units did trip off line prematurely due to conservative setting of generator
protection systems, no evidence has been provided that transformer tripping
contributed to the cause of the generation outages. The sole purpose as stated by the
SDT for including transformers is a directive from FERC. We believe that there should
be some evidence as to the benefit of preforming protection modifications to

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Question 3 Comment
transformers and that they should not simply be included until a study can be
performed to show the cost benefit analysis and therefore recommend that
transformers be excluded during this phase and be incorporated into a phase III.
Response: FERC has already ruled on entities’ requests for clarification and rehearing
on Order 733 with regard to this matter. The drafting team notes that entities may
change the configuration or operation of their network to facilitate compliance but not
to eliminate a compliance obligation. No change made.
If transformers are to be included, an exception should be provided to allow the startup transformer to be used to provide auxiliary power in case of failure of the auxiliary
transformer. BES reliability is better served by allowing this exception (which will occur
very infrequently) than to keep the generating unit off line for fear of being out of
compliance with a standard.
Response: The drafting team contends that if this is an anticipated operating condition,
the protective relays on the alternate source of station service would need to be
compliant with the standard. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Bonneville Power
Administration

No

While the Guidelines and Technical Basis provides useful information, BPA is
concerned that this document will not be approved by FERC as part of the standard
and thus the standard must be capable of standing on its own. For this reason, BPA
requests that clarification provided in the Guidelines and Technical Basis document be
included into the standard specifically in regards to ‘generator interconnection
facilities’.

Response: The drafting team thanks you for your comments and will re-append the Guidelines and Technical Basis document to
the standard prior to filing with FERC. The documents were separated for management purposes and to facilitate editing
between team members. No change made.

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AESI Inc.

Yes or No
No

Question 3 Comment
Please see comments on Question 2.

Response: The drafting team thanks you for your comments; please see the above responses in question 2.
Western Farmers
Electric Cooperative

No

See comments to question 5

Response: The drafting team thanks you for your comments; please see the responses below in question 5.
Xcel Energy

No

In the last paragraph on page 19 of the clean version of the PRC-025-1 Guidelines and
Technical Basis, the following sentence appears:
"Phase time overcurrent relays applied to the UAT that act to trip the generator
directly or via lockout or auxiliary tripping relay are to be compliant with the relay
setting criteria in this standard."
This typically would be the case for UAT's connected to the generator bus. However,
for system connected auxiliary transformers as shown in Fig 6 on page 20, it is very
unlikely that the time overcurrent relays protecting the system connected
transformers will act to trip the generator directly or via lockout as this is a different
zone of protection and to do so might result in an unnecessary challenge of the unit's
overspeed protection. Instead, these overcurrent relays will trip the source breakers
feeding the system connected auxiliary transformer but will not act to directly trip the
generator. The generator will ultimately trip because of the resultant loss of power to
the auxiliary system when the source breakers feeding the auxiliary transformer are
tripped. The loss of auxiliary power will likely result in some form of a turbine/prime
move trip and the generator breaker will be tripped open once power output drops to
zero. In this manner, unit overspeed protection is not unnecessarily challenged. It
seems that the quoted sentence on page 19 only serves to confuse the matter. If the
goal of this setting requirement is to not to have the plant trip due to a loss of auxiliary
power based on overly conservative setting of overcurrent relays, it is immaterial

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Yes or No

Question 3 Comment
whether the overcurrent relays act to trip the generator directly or via lockout or
auxiliary tripping relay or if the plant ultimately trips because a loss of auxiliary power
caused by overcurrent relays opening source breakers to the system connected
auxiliary transformer. We recommend the quoted sentence be stricken from the
guideline and technical basis document.

Response: The drafting team thanks you for your comments and contends that the load-responsive protection for any UAT that
supplies “running station power” to the plant, such that tripping of the UAT will cause the generator to trip, should be addressed
by the draft standard. The drafting team has revised the Table 1 criteria for UAT protection in the Standard and the Guidelines
and Technical Basis discussion accordingly. Change made.
ReliabilityFirst

No

1) There appears to be an error in the Guidelines and Technical Basis document on
page 23 for option 15b. It indicates that the Reactive Power output that equates 120%
of the maximum gross Mvar output whereas Table 1 states 100%.
Response: Yes, this was an error in the Guidelines and Technical Basis document for
Option 15b. The value should be 100% of the output determined by simulation like the
other options. Change made.
2) A statement should be inserted that the iterative calculation stopped because the
change was < 1%. This applies to options 1b & 7b on page 31 and option 2b on page
38. Also, if an entity knows the resistive and reactive impedances of the transformer,
the entity could directly calculate the low-side GSU voltage from the high-side voltage,
the per unit current through the GSU and the full impedance of the transformer.
Response: This convergence of the equation is addressed for Options 1b and 7b in the
calculations above Equation 14. This text was not provided in the calculation for
Option 2b; therefore, it will be added to improve overall clarity. There are two
variables in this calculation which depend on each other; therefore iteration is
necessary. Change made.

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Yes or No

Question 3 Comment

Response: The drafting team thanks you for your comments; please see the above responses.
Ameren

No

(1) We request the SDT to add a multiple winding transformer example. We
recommend that the SDT include an example with equally rated CTGs connected to
equally rated dual secondary transformer windings stepping up to a single high voltage
winding, because it is commonly used.
Response: For the configuration above, the GSU relays will be set on an aggregated
generator basis. The generator relay setting will be set on an individual generator
basis. The drafting team contends that the calculations provide adequate direction for
this configuration. No change made.
(2) The MW capability reported to the Transmission Planner changes by a very small
amount from time to time. As written we believe that this could trigger a significant
amount of documentation. We request the SDT to show in your example (s) how an
increased margin would address such a small change (e.g. a 2% increase from the
originally documented value) before triggering such a review.
Response: The drafting team contends that if an entity is concerned about minor
changes in the reported capability, the entity can reflect these minor changes as
increased margin in their relay setting. No change made.
(3) On page 2 of the Guidelines and Technical Basis document, we ask the SDT to
delete 'Generator Owner' from the last sentence of Figure 2 caption.
Response: This was recognized as an error after the posting. The “Generator Owner”
has been removed from the Figure 2 text. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Luminant Generation

No

Figures 1, 2, and 3 do not provide a sufficient bright line between the application of
PRC-025-1 and PRC-023-3 for setting criterion. Luminant recommends that additional

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Question 3 Comment
information be added that identifies that a load responsive relays located on the
transmission line breaker at Bus A and are primarily installed for transmission line
protection use PRC-023-3 criterion Requirements R1 through R6 (regardless of the
number of generators or transmission lines connected to Bus A). Load responsive
relays located on the high side of the GSU and are primarily used for failed
transmission line protection should use PRC-023-3 (Attachment C) or PRC-025 (Table
1).

Response: The drafting team thanks you for your comment and notes that load-responsive protective relays applied on
"Elements that connect a GSU to the Transmission system and are used exclusively to export energy directly from a BES
generating unit or generating plant" (which replaces the previously-used term, “generator interconnection Facility”) are covered
under the proposed PRC-025-1 standard. Load-responsive protective relays applied on network transmission lines are covered
under the proposed PRC-023-3 standard. Please refer to the revised Figures 1, 2, and 3 in the proposed PRC-025-1 Guidelines and
Technical Basis for further information on applications. Change made.
Tri-State G&T

No

The generator overload protection exception added to Draft 3 for extremely inverse
characteristics is a major improvement, but the term “full-load current” needs
clarification. Is this the current at normal full-load turbine output and typical PF, or the
value determined from the generator nameplate MVA at rated voltage, or the base (no
fans, no oil circulation) rating of the GSU?

Response: The drafting team thanks you for your comments and notes that the phrase full load current refers to rated armature
current of the generator. No change made.
Luminant Energy
Company LLC

No

See Luminant Generation Company LLC comments.

Response: The drafting team thanks you for your comments; please see the response(s) for Luminant Generation Company LLC.
Entergy Services, Inc.

No

The Guidelines are still not clear about what to do with start-up transformers when

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57

Organization

Yes or No

(Transmission)

Question 3 Comment
used in lieu of the UATs (Unit Auxiliary Transformer).

Response: The drafting team thanks you for your comments and contends that if this is an anticipated operating condition, the
protective relays on the alternate source of station service would need to be compliant with the standard. No change made.
Tennessee Valley
Authority

No

Operational
Compliance

Yes

See comments for Question #1.
In addition, Figures 1,2 and 3 could be clarified by
1) labelling the Generator Interconnection Facility with a pointer and parentheses,
2) include table with columns for Relay Owners, Function of Owner and Applicable
Standard. This way, a quick glance at the figure can clarify which standard is applicable
(rather than having to decipher the caption).

Response: The drafting team thanks you for your comment and notes that load-responsive protective relays applied on
"Elements that connect a GSU to the Transmission system and are used exclusively to export energy directly from a BES
generating unit or generating plant" (which replaces the previously-used term, “generator interconnection Facility”) are covered
under the proposed PRC-025-1 standard. Load-responsive protective relays applied on network transmission lines are covered
under the proposed PRC-023-3 standard. Please refer to the revised Figures 1, 2, and 3 in the proposed PRC-025-1 Guidelines and
Technical Basis for further information on applications. Change made.
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company; Gulf
Power Company;

Yes

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Organization

Yes or No

Question 3 Comment

Mississippi Power
Company; Southern
Company Generation;
Southern Company
Generation and
Energy Marketing
FirstEnergy

Yes

MRO NERC Standards
Review Forum

Yes

SERC Protection and
Controls
Subcommittee

Yes

Dominion

Yes

PacifiCorp

Yes

Idaho Power Company

Yes

Independent
Electricity System
Operator

Yes

Northeast Utilities

Yes

Manitoba Hydro

Yes

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
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Organization

Yes or No

American Electric
Power

Yes

Tacoma Power

Yes

South Carolina Electric
and Gas

Yes

Ingleside
Cogeneration LP

Yes

Southwest Power Pool

Yes

Kansas City Power and
Light

Yes

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

Question 3 Comment

60

4.

The drafting team developed an Implementation Plan for the added requirements of the proposed PRC-023-3 that aligns
with that proposed in PRC-025-1. Do you agree with the proposed Implementation Plan for PRC-023-3 Requirements R7
and R8 and the proposed PRC-025-1: a. 48-months to apply load-responsive protective relay settings , where relay
replacement is not required, and b. 72-months to apply load-responsive protective relay settings, where relay
replacement is required? If not, provide an alternative implementation plan with specific rationale for such an alternative
period.

Summary Consideration: Only a minority of commenters provided comments regarding the Implementation Plan. In past postings, a
number of commenters suggested increasing the Implementation Plan due to varying factors. The drafting team was reluctant to
increase the period beyond the 48 months for applying settings on relays that do not requirement replacement and 72 months for
those relays which require replacement or removal. Four comments supported by 11 entities propose lengthening the period in
these comments. However, based on other factors identified in question 2, the drafting team has lengthened the Implementation
Plan from 48 to 60 months for applying settings on relays that do not requirement replacement and from 72 to 84 months for those
relays which require replacement or removal.
One comment noted a lack of clarity on the implementation of PRC-023-3. The drafting resolved that by removing the proposed
Requirements R7 and R8 and adding the Distribution Provider and Transmission Owner to PRC-023-3. One comment suggested
adding the word “removed” in the “replacement” timeframe for clarity. The drafting team agreed and made the change. Another
comment disagreed with the 100 percent compliance approach. The drafting team did not have any flexibility to investigate other
compliance approaches. One comment suggested a phased approach to the Implementation Plan; however, the drafting team
agreed the current two-phased approach is the most practical. Last, one comment suggested adding formatting to the effective date
language to draw attention to “do require replacement” and “do not requirement replacement.” The drafting team did not agree
the suggestion provided a substantive improvement to clarity.

Organization

Yes or No

Duke Energy

No

Question 4 Comment
Duke Energy schedules some of its generating units on a 24 month cycle for minor
outages and a 96 month cycle for major outages. This would make the current

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Organization

Yes or No

Question 4 Comment
Implementation Plan very expensive and difficult to comply with if relay replacements
are required. [Duke Energy suggests a 48 month and 96 month Implementation Plan.
This would allow for the industry to use existing outage schedules, keeping overall costs
at a minimum.]

Response: The drafting team thanks you for your comment and has increased the implementation period from 48 months to 60
months for applying settings on load-responsive protective relays that do not require replacement or removal, and from 72
months to 84 months for applying settings on load-responsive protective relays that do require replacement or removal to
prevent an implementation gap with the MOD-25-2 standard which is pending regulatory approval. Change made.
JEA

No

Considering that applying new settings and testing will require a major outage, we
believe that 48 months is not a sufficient time frame for full implementation when
existing equipment can be used and relay replacement is not required. We recommend
72 months be allowed even in the case where existing equipment can be used. It may
take a year or more to perform the calculations and evaluated equipment and then
another 5 years for a major planned outage to occur.

Response: The drafting team thanks you for your comment and has increased the implementation period from 48 months to 60
months for applying settings on load-responsive protective relays that do not require replacement or removal, and from 72
months to 84 months for applying settings on load-responsive protective relays that do require replacement or removal to
prevent an implementation gap with the MOD-25-2 standard which is pending regulatory approval. Change made.
DTE Electric

No

Comments: Suggest that allowing 72 months to become 100% compliant for both 4a
and 4b would better align with the unmonitored protective relay maximum
maintenance interval of 6 years specified in PRC-005-2. In this way, relay setting
changes or replacements could be accommodated during normal scheduled relay
maintenance. Also, 48 months could be difficult to achieve for a company with a large
generation fleet.

Response: The drafting team thanks you for your comment and has increased the implementation period from 48 months to 60

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Organization

Yes or No

Question 4 Comment

months for applying settings on load-responsive protective relays that do not require replacement or removal, and from 72
months to 84 months for applying settings on load-responsive protective relays that do require replacement or removal to
prevent an implementation gap with the MOD-25-2 standard which is pending regulatory approval. Change made.
Also, it is beyond the drafting team’s control to ensure that a standard is approved and implemented in such a way to facilitate
alignment with the implementation of other standards. No change made.
American Electric
Power

No

Regarding PRC-025-1: While AEP appreciates the factors considered by the drafting
team when developing the proposed implementation plan for PRC-025-1, the plan as
proposed will not afford adequate time for large Generator Owners to comply with the
standards.
AEP has 119 generating units and 2 wind farms that are applicable to PRC-025-1. The
resources needed to evaluate the generating units for compliance with PRC-025-1 and
PRC-023-3 will also be engaged in implementing the new NERC standards PRC-019-1
and PRC-024-1. For these reasons, AEP believes a phased implementation plan for PRC025-1 is more appropriate. Such a plan would require entities to show that a minimum
percentage of their applicable relays are compliant within a specified time frame.
For example:
* Entities shall demonstrate that 30% of their applicable load-responsive
protective relays are fully compliant with R1 within 48 months of the effective
date of this standard.
* Entities shall demonstrate that 60% of their applicable load-responsive
protective relays are fully compliant with R1 within 60 months of the effective
date of this standard.
* Entities shall demonstrate that 100% of their applicable load-responsive
protective relays are fully compliant with R1 within 72 months of the effective
date of this standard.
Regarding PRC-023-3: The proposed revision could significantly impact Transmission

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Organization

Yes or No

Question 4 Comment
Owners. Additional research is being conducted within AEP Transmission to determine
the extent of that impact. It is possible that the proposed implementation plan would
not provide adequate time to achieve compliance with the standard if it is determined
to impact a high volume of facilities. Additional research will be needed before a
recommendation be made on the extent the additional time required.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into PRC-025-1, rather than adding Requirement R7 and R8 to
PRC-023-2. All implementation will be addressed within the Implementation Plan for
PRC-025-1.
The drafting team thanks you for your comment and has increased the implementation
period from 48 months to 60 months for applying settings on load-responsive
protective relays that do not require replacement or removal, and from 72 months to
84 months for applying settings on load-responsive protective relays that do require
replacement or removal to prevent an implementation gap with the MOD-25-2
standard which is pending regulatory approval. Change made.
The suggested phased-in approach would be potentially unfair to small entities
requiring them to become 100% compliant earlier. No change made.
It is still unclear when TOs, GOs and DPs will be required to complete loadability
evaluations for any circuits below 200kV included by the Planning Coordinator per
Attachment B. It is understood that we will have 39 months to apply the initial list.
There is confusion however on whether or not the 39 months applies to new inclusions
to the list. AEP requests that this time frame be clarified and included in the standard,
as it is information needed to maintain compliance on an ongoing basis.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement R7
and R8 to the proposed PRC-023-3 to establish a bright line between the two standards.
The owner of load-responsive protective relays applied to generation-related Facilities

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Organization

Yes or No

Question 4 Comment
will be in PRC-025 and owner of load-responsive protective relays network-related
Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
All implementation will be addressed within the Implementation Plan for PRC-025-1,
and no changes are being made to the existing approved PRC-023-2 Implementation
Plan.

Response: The drafting team thanks you for your comments; please see the above responses.
Luminant Generation

No

Luminant recommends that the phrase “where relay replacement is not required” and
“where relay replacement is required” add the word removal; i.e., “replacement or
removal”.

Response: The drafting team thanks you for your comments and the drafting team has revised items #7 and #8 in the General
Considerations of the PRC-025-1 Implementation Plan as you suggest. Change made.
Ingleside
Cogeneration LP

No

Ingleside Cogeneration LP does not agree with the 100% compliance approach that the
drafting team has taken in regard to PRC-025-1. Although FERC Order 733 is cited
multiple times as the reliability need, there are real dollars that the industry will need to
expend to analyze and replace load responsive relays for generators of any size. We do
not read Order 733 the same way - and FERC has accepted exceptions for low-impact
facilities in the past.

Response: The drafting team contends that the requirements proposed within PRC-025-1 satisfy the associated FERC directive
and are appropriate and necessary. Appendix 4B, Section 2 of the NERC Rules of Procedures identify and discuss the basic
principles underpinning why and how NERC and the Regional Entities will determine Penalties, sanctions, and Remedial action
Directives for violations of the Requirements of the Reliability Standards. By being classified as BES, the facilities involved have
been determined to have impact on the reliability of the BES. No change made.
Luminant Energy

No

See Luminant Generation Company LLC comments.

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
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Organization

Yes or No

Question 4 Comment

Company LLC
Response: The drafting team thanks you for your comments; please see the response(s) for Luminant Generation Company LLC.
ACES Standards
Collaborators

Yes

We agree with the 48-month and 72-month implementation plan for PRC-025 and R7
and R8 in PRC-023. However, we believe the implementation plan for PRC-023 as a
whole is confusing. Since PRC-023-2 has a staggered implementation plan that is still
has not fully been implemented, we recommend laying out a graphical timeline or a
Gantt chart that compares PRC-023-2 implementation to that of PRC-023-3.

Response: The drafting team thanks you for your comment and has increased the implementation period from 48 months to 60
months for applying settings on load-responsive protective relays that do not require replacement or removal, and from 72
months to 84 months for applying settings on load-responsive protective relays that do require replacement or removal to
prevent an implementation gap with the MOD-25-2 standard which is pending regulatory approval. Change made.
The drafting team has decided to integrate Transmission Owner and Distribution Provider into the proposed PRC-025-1, rather
than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two standards. The owner
of load-responsive protective relays applied to generation-related Facilities will be in PRC-025 and owner of load-responsive
protective relays network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3, the Implementation Plan has been revised to note
the specific milestones that are known to improve clarity. Change made.
The drafting team is unable to provide a graphical timeline comparison between the standards illustrating their implementation
because each is subject to NERC Board of Trustees adoption and subsequent regulatory approvals. No change made.
Operational
Compliance

Yes

Editorial note:
To aid with distinguishing between options: underline the words “is necessary” and “is
not necessary” for “Implementation Date” columns.

Response: The drafting team thanks you for your comments and contends that it is not necessary to add the emphasis suggested.

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Organization

Yes or No

Question 4 Comment

No change made.
Pepco Holdings Inc. &
Afffiliates

Yes

FirstEnergy

Yes

MRO NERC Standards
Review Forum

Yes

SERC Protection and
Controls
Subcommittee

Yes

PPL NERC Registered
Affiliates

Yes

Western Area Power
Administration

Yes

Dominion

Yes

Bonneville Power
Administration

Yes

PacifiCorp

Yes

AESI Inc.

Yes

Chelan County PUD

Yes

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Organization

Yes or No

Idaho Power Company

Yes

Xcel Energy

Yes

Independent
Electricity System
Operator

Yes

Northeast Utilities

Yes

Manitoba Hydro

Yes

ReliabilityFirst

Yes

Ameren

Yes

Tacoma Power

Yes

South Carolina Electric
and Gas

Yes

Entergy Services, Inc.
(Transmission)

Yes

Southwest Power Pool

Yes

Kansas City Power and
Light

Yes

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
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Question 4 Comment

68

5.

Do you have any other comments? If so, please provide suggested changes and rationale.

Summary Consideration: The general section of the comments contain varying issues, some being majority issues that have been
addressed in previous postings. There are approximately ten chief concerns. (1) About eight comments supported by 45
stakeholders disagreed that the unit auxiliary transformer (UAT) should be addressed in the standard. The drafting revised the
criteria for the UAT to address only those relays on the high-side terminals of the UAT. The drafting team acknowledges the varying
configurations of station service supply and agrees that addressing loadability of the UAT is best satisfied at the high-side terminals
of the UAT to be responsive to the FERC directive to include them. (2) Approximately five comments represented by about 41
entities disagree with the singe Violation Severity Level (VSL) of Severe. The drafting team contends it has followed the VSL
Guidelines and notes that the requirement applies to each load-responsive protective relay. Violations would be evaluated on a case
by case basis through the auditing and enforcement process. (3) About six comment supported by 36 stakeholders disagreed with
the inclusion or impacts the standard would have on Blackstart generation units and dispersed generation. The drafting team
considered these issues and determined that the governing factor should be the application of the Bulk Electric System definition
which addresses whether a unit or plant is BES based on individual unit size or site aggregate capacity. (4) Four comments
representing about 29 entities disagreed or requested clarity about the use of the phrase “generation interconnection Facilities.”
The drafting team addressed this by rephrasing this criterion to avoid confusion with the common understanding. See Question 1
summary and comment responses for more detail. (5) Two comments supported by about 28 individuals desired an approach similar
to the PRC-024 standard. The drafting team noted that PRC-024 is based on equipment potentially being damaged and the proposed
PRC-025-1 standard criteria achieve its loadability goal in conditions that are not damaging to the generator. (6) Approximately three
comments represented by 19 stakeholders suggested using the generator nameplate to reduce the complexity of the criteria. The
drafting team addressed this in prior postings and in the above summaries. The proposed PRC-025-1 standard takes into
consideration that some generation units may not operate near nameplate capacity; therefore, using a nameplate value would be
result in an overly conservative setting. (7) Two comments representing 19 individuals did not agree with the intent of the standard.
The drafting team is certain that is has fulfilled its responsibility in meeting the objectives of the project to address load-responsive
protective relay loadability for generation Facilities. (8) Three comments supported by about 18 entities expressed concern about
the proposed Requirements R7 and R8 in PRC-023-3. The drafting team removed these requirements and added the Distribution
Provider and Transmission Owner in PRC-025-1. See the above summaries and comments for more detail. (9) About four comments
supported by 11 stakeholders raise concerns about overloading and the application of ANSI standards in relation to the PRC-025-1

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standard. The drafting team provided responses to help clarify the differences. Please see the individual responses for greater clarity
on overload issues. (10) The last of the chief concerns were noted in three comments represented by 12 individuals who expressed
disagreement with a Violation Risk Factor (VRF) of High. The drafting team notes that the assignment of the VRF follows VRF
guidelines.
The following summary addresses concerns of two or fewer comments and less than ten individuals. Stakeholders continued to have
concerns about the phrase “while maintaining reliable fault protection.” This phrase has been used in previous versions of PRC-023
and the drafting team agrees that it is clear on the expectation. Comments supported by about six entities requested terms in PRC023-3 to be capitalized to represent NERC glossary definition terms; however, the drafting team did not address these as they are
outside the scope of the approved objectives of the project. Another set of comments supported by about eight individuals
requested the removal of the “Regional Reliability Organization (RRO) from the standard. The drafting removed this language and to
address the potential gap in doing so, increased the Implementation Plan periods by one year. See the summary in Question 2 and
individual responses for more detail. Last, single comments asked for clarification of BES generators, minor edits and corrections,
Implementation Plan edits, and consideration of the Reliability Standard Audit Worksheet (RSAW) and the Cost Effective Analysis
Process (CEAP). See the responses for the RSAW and CEAP for additional detail.

Organization

Yes or No

Pepco Holdings Inc. &
Afffiliates

No

Western Area Power
Administration

No

Duke Energy

No

PacifiCorp

No

Idaho Power
Company

No

Consideration of Comments: Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3 and PRC-025-1 | June 10, 2013

Question 5 Comment

70

Organization

Yes or No

Independent
Electricity System
Operator

No

Northeast Utilities

No

South Carolina
Electric and Gas

No

Luminant Generation

No

Luminant Energy
Company LLC

No

Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company; Gulf
Power Company;
Mississippi Power
Company; Southern
Company
Generation; Southern
Company Generation
and Energy
Marketing

Yes

Question 5 Comment

2) We suggest removing Section 3.2.3 and footnote 1. UAT protection is part of the
station service system and should not be in this standard. Remove the UAT from
Table 1. The UAT relays are not in the category of “all load-responsive protective
relays that are affected by increased generator output in response to system
disturbances.” The highside overcurrent pickup should not be required to be at 150%.
Settings at > & = 115% should be allowed.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
The specified relays are affected by the conditions being addressed by the standard,
and thus need to be addressed. The drafting team has proposed a 150% multiplier for
these relays rather than requiring an analysis of the connected loads for depressed
voltage; the margin includes consideration for the increased current called for by these

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Organization

Yes or No

Question 5 Comment
loads as well as normal relay setting tolerances. No change made.
3) We believe that the Purpose statement should end "... do not pose a risk of
damaging the generator."
Response: The Purpose statement was modified in the last draft to not be generator
specific. The standard addresses generation Facilities in general and the criteria
provide reasonable loadability settings that are within the capability of the equipment
the standard is addressing. The purpose statement has been modified to clarify risk to
associated equipment. Change made.
4) The protection of the generator should be the paramount concern. All ANSI
standards for generator and main power transformer protection should be considered
to be the ruling guide for protecting the equipment. The minimum allowable settings
provided in the table in the draft standard do not factor using time delays in order to
provide adequate protection for generators.
Response: The ANSI/IEEE standards are voluntary and are generally written from an
equipment-specific perspective. The drafting team notes that they do, in many cases,
mention system performance, and the concerns noted in the ANSI/IEEE standards for
system performance do not differ greatly from the criteria proposed in PRC-025-1. The
drafting team further notes that the IEEE working groups that develop these standards
are considering revisions to the affected standards to align with the Power Plant and
Transmission System Protection Coordination document authored by the NERC SPCS.
Finally, the drafting team notes that the last two bullets in the Exceptions in PRC-025-1
Attachment 1 address overload protection. No change made.
5) The overload relay that protects the generator from overload may also be the relay
that protects the GSU from overload. In the exception list of the draft standard,
exception bullet #5 should take precedence over exception bullet #6.
Response: In the example noted bullet #5 is applicable and bullet #6 is not. Therefore,
the relay is exempted under bullet #5. No change made.

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Organization

Yes or No

Question 5 Comment
6) The protection requirements (exception bullet #5) from the ANSI standards need
additional recognition, development, and emphasis in the Exceptions section. As
written, it appears to be an afterthought. The ANSI standard for synchronous
generator protection should be recognized, respected, and not violated. The Table 1
setting specifications which contradict the ANSI standards should be submissive to the
ANSI standards and itemized in the exception criteria. Consider removing “extremely”
from the "extremely inverse time" description as various vendors call the varying
inverse time curve by different names.
Response: The ANSI/IEEE standards are written from an equipment-specific
perspective, and largely disregard system performance concerns. The drafting team
notes that they do, in many cases, briefly mention system performance, and the
concerns noted in the ANSI/IEEE standards for system performance do not differ
greatly from the criteria proposed in PRC-025-1. The drafting team intends that
“extremely inverse characteristic” be applied consistently with IEEE C37.112, “IEEE
Standard Inverse-Time Characteristic Equations for Overcurrent Relays.” No change
made.
7) The generator overload protection exception added to Draft 3 for extremely inverse
characteristics (fifth exception bullet) is an improvement, but the term “full-load
current” needs clarification. Is this the current at normal full-load turbine output and
typical PF, the value determined from the generator nameplate MVA at rated voltage,
or is it the base or top (no fans, no oil circulation) MVA rating of the GSU?
Response: The drafting team notes that the phrase full load current refers to rated
armature current of the generator. No change made.
8) The wording in the sixth exception bullet of the Exceptions section is too vague.
How much of an overload is considered an overload? Many vendor relay curves do not
provide characteristics showing the value of current that will time out in 15 minutes. It
may be difficult to prove a setting to provide 15 minute delay. Existing relays in service

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Organization

Yes or No

Question 5 Comment
do not have the ability to be set by this criterion.
Response: The drafting team does not intend to define what an overload is, but
instead to exempt schemes that are explicitly designed for overload protection, for
which characteristics would be defined for the time period in the bullet. Loadresponsive relays that respond otherwise must meet the criteria in Table 1. No change
made.
9) The Exceptions section seems to state that the exceptions are allowed only during
start up and when off line, which is unacceptable. The exceptions should be allowed at
all times.
Response: The drafting team has revised the exceptions portions of Attachment 1 to
address your concerns by inserting a specific numbered exception to adder relay
elements that are in service only during startup. Change made.
10) To meet the requirements of table 1 for non-51 relays (distance relays set at
approximately 180% of generator MVA) and meet our protection philosophy
objectives, we would have to install many new relays for overload protection.
Response: The drafting team understands that in some cases it may be necessary to
replace existing relay equipment. No change made.
11) Determination of the pickup of the distance relays is too complicated. The
calculated impedance should be based on generator nameplate MVA and pf only.
The requirements make what should be a simple calculation based on generator
electrical characteristics into one that will require the relay engineer to find test MW
data is not readily unavailable.
Response: The drafting team intentionally did not reference the calculation to
nameplate MVA for the Real Power portion of the calculation because this would
result in an overly conservative setting for units that cannot achieve the nameplate
capability. The test megawatt data must be reported and should be readily available.

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Organization

Yes or No

Question 5 Comment
No change made.
12) PRC-025 should be revised to "grandfather" existing protection settings that have
been proven in practice for many decades not to prematurely remove equipment from
service.
Response: The drafting team has developed the standard in accordance with the
regulatory directive concerning generator relay loadability, which is an outcome of the
2003 blackout report. As noted in the NERC document ‘Power Plant and Transmission
System Coordination’ – July 2010, at least 28 generators were tripped on August 14,
2003 by load-responsive phase protection; eight of those by phase distance and 20
more by 51V protection. For many of these generators, the legacy protective
equipment had been previously believed to not prematurely remove equipment. No
change made.
13) The applicability of PRC-025 should exclude small gensets that are NERC-registered
solely due to being black start-capable, whose tripping would not meaningfully affect
the ability of the system to ride through Disturbances. It would be best to allow such
units to maintain their present loadability relay settings for retoration purposes.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the
applicability of the standard, they may not perform as expected to facilitate system
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan
(i.e., SRP). No change made.
14) Voltage-restrained overcurrent relays are notorious for not having a predictable
operation time under fault conditions. If they are included in the types of equipment
that mis-operated in the August 2003 blackout, they should be required to be replaced
with another relay type rather than requiring that the settings be relaxed to the degree

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specified in the draft standard.
Response: The drafting team agrees, in general, that these devices are not
recommended and, where used, that these devices should be replaced. However, as
the drafting team is unable to require that such relays be replaced, applicable criteria
are provided. No change made.
15) A High VRF and a Severe VSL seems overly harsh given the compliance feasibility
uncertainties.
Response: The VRF criteria are based on the risk to the system if a requirement is
violated, and the VSL criteria are based on the degree of non-compliance. Alleged
difficulties in achieving compliance are not a factor in the criteria for either VRFs or
VSLs. No change made.
16) Which UATs are proposed to be included, if any, is confusing. Suggest adding
diagrams to the reference document.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
17) During the webinar there were three slides related to the different trans to Gen
interconnections and who is responsible for what; suggest adding and or clarifying
these in the reference documents.
Response: The drafting team thanks you for your comment and notes that loadresponsive protective relays applied on "Elements that connect a GSU to the
Transmission system and are used exclusively to export energy directly from a BES
generating unit or generating plant" (which replaces the previously-used term,
“generator interconnection Facility”) are covered under the proposed PRC-025-1
standard. Load-responsive protective relays applied on network transmission lines are

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covered under the proposed PRC-023-3 standard. Please refer to the revised Figures 1,
2, and 3 in the proposed PRC-025-1 Guidelines and Technical Basis for further
information on applications. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Northeast Power
Coordinating Council

Yes

In PRC-023-3, add “Each” to the beginning of R8.

Response: The drafting team thanks you for your comment and notes that the comment above is no longer relevant because:
The drafting team has decided to integrate Transmission Owner and Distribution Provider into the proposed PRC-025-1, rather
than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two standards. The owner
of load-responsive protective relays applied to generation-related Facilities will be in PRC-025 and owner of load-responsive
protective relays network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
FirstEnergy

Yes

FE believes that that the term "generator interconnection Facility" should be a NERC
defined term in the Glossary since it is used in other standards, ie, PRC-005, or at the
very least, be defined within the standard(s). This term is only defined in the
Guidelines and Technical Basis.
In the Guidelines and Technical Basis, Figure 2 has a typo on the 3rd sentence and
should read as follows: If the Distribution Provider or Transmission Owner owns these
relay, they are responsible for them under PRC-023.

Response: The drafting team has replaced this term with "Elements that connect a GSU to the Transmission system and are used
exclusively to export energy directly from a BES generating unit or generating plant." Change made.
SERC Protection and
Controls
Subcommittee

Yes

There were three one-line reference drawings described on the webinar. Suggest
adding text to these reference drawings or add descriptive wording in reference
documents to better explain responsibilities of relay owners for these various

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configurations. On the webinar there were repetitive questions about these
configurations so this would indicate confusion. Also, would suggest adding another
drawing to illustrate when you have a generating station where the GO owns GSU
relays and the TO owns relays between the GSU and switchyard to clarify that the TO is
only responsible for R7 in PRC023-3 and not R8 since the GSU relays are a GO asset.

Response: The drafting team thanks you for your comments and notes that these figures are already included in the Guidelines
and Technical Basis, along with discussion. No change made.
PPL NERC Registered
Affiliates

Yes

: The PPL NERC Registered Affiliates reiterate their concern in regards to the following
comments. The Application Guidelines state that the reliability objective of PRC-025 is
to cover, “all load-responsive protective relays that are affected by increased
generator output in response to system disturbances.” Unit Auxiliary Transformers
(UAT’s) are not in this category and should therefore be excluded from the
Applicability of the Standard in Section 3.2.3.The point was made in the 5/15/13
webinar that a decrease in HV system voltage would affect the plant MV voltage as
well, causing a proportional increase in current (at constant power draw by plant
auxiliary loads) and thereby potentially tripping UAT loadability relays. Reduction in
frequency during disturbances will strongly reduce the power draw of pumps and fans,
however, so MV current may actually drop despite the HV voltage reduction being
experienced. This point of view is supported by the statement in the 12/13/2012
webinar that UAT relay trips are not known to have caused the loss of any generation
units during the northeast blackout of ‘03, so extending PRC-025 applicability to UATs
provides only a hypothetical benefit that has not been observed (or has in fact been
disproved) in practice.
The PPL NERC Registered Affiliates again state that Facilities’ UATs in Section 3.2.3 do
not belong in this standard as no technical justification has been provided. An
investigation and evaluation of the protection systems for unit auxiliary transformers
and the UAT’s lack of impact on generator loadability should be considered by the SDT.

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A cost-benefit analysis for generator UATs should be performed to demonstrate that
net benefits will result from any such standard before it is proposed. Without such an
analysis, the standard may result in costs without a sufficient reliability benefit and
may in some cases actually lessen reliability (see item 5 below).
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
2.) The generator overload protection exception added to Draft 3 for “extremely
inverse characteristics” (5th bull-dot) is a major improvement, but the term “full-load
current” needs clarification The PPL NERC Registered Affiliates suggest that the SDT
state in the Guidelines and Technical Basis that “full-load current” is understood to be
the generator nameplate MVA at rated voltage
Response: The drafting team notes that the phrase full load current refers to rated
armature current of the generator. No change made.
3.) The overload protection exception added to Draft 3 for “extremely inverse
characteristics” should be applied for UAT’s as well if eliminating UAT’s in its entirety
(per comment #1 above) does not prove feasible.
Response: The exclusion #7 addresses transformers and is not limited to only GSUs. No
change made.
4.) The PPL NERC Registered Affiliates reiterate their concern in regards to the
following comments. PRC-025 should be revised to grandfather existing major
equipment, similar to the approach recently used for PRC-024. It may not always be
possible to develop PRC-025-conforming means of protection without replacing GSUs
or UATs; and, in the absence of any compensation to the owner, it would be
inappropriate to outlaw equipment that was acceptable under the rules in effect at the

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time it was installed.
Response: The drafting team contends that it is possible to provide phase fault backup
protection while meeting the requirements of this standard. The drafting team notes
that the standard provides multiple options for setting transformer load-responsive
phase relays to address this concern. If legacy approaches do not allow the entity to
meet the requirement and protection objectives, other approaches may be necessary.
To prevent equipment damage from excessive time exposed to overload conditions,
the drafting team has included exclusions for dedicated generator and transformer
overload protection that operates in time frames appropriate to overload protection.
No change made.
5.) The applicability of PRC-025 should exclude small gensets that are NERC-registered
solely due to being black start-capable, the tripping of which would not meaningfully
affect the ability of the system to ride through Disturbances. It would be best to allow
such units to maintain their present loadability relay settings, if they are consistent
with a reasonable coordination study, rather than mandate upgrades that augment the
degree to which NERC requirements have already eliminated any economic rationale
for having black-start facilities. Given the numerous CIP standards in effect to afford
protection to the critical BS restoration facilities, it would be contradictory to impose a
standard that could potentially increase risk of damage to a BlackStart Generator by
forcing the BS facility to ride through the disturbance. If that disturbance is a
precursor to a blackout, then having BS Resource unavailable to facilitate system
restoration would defeat the purpose of designating it as a Blackstart Resource.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the
applicability of the standard, they may not perform as expected to facilitate system
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan

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(i.e., SRP). No change made.
6.) The PPL NERC Registered Affiliates reiterate their concern in regards to the
following comments. Regarding in particular voltage-restrained overcurrent relays,
this type of device is known for not having a predictable operation time under fault
conditions. If they did mis-operate in the August 2003 blackout they should be
changed-out rather than requiring that the settings be set as high as specified in the
draft standard.
Response: The drafting team agrees, in general, that these devices are not
recommended and, where used, that these devices should be replaced. However, as
the drafting team is unable to require that such relays be replaced, applicable criteria
are provided. No change made.
7.) Deeming any and all violations of this standard to have a high violation risk factor
and a severe violation severity level seems overly harsh, given the compliance
feasibility uncertainties expressed above.
Response: The VRF criteria are based on the risk to the system if a requirement is
violated, and the VSL criteria are based on the degree of non-compliance. Alleged
difficulties in achieving compliance are not a factor in the criteria for either VRFs or
VSLs. No change made.
8.) The compliance uncertainties expressed above also promote the use of risk based
compliance approach rather than a zero tolerance policy. Other standards in
development (CIP V5 standards) no longer dictate a zero tolerance policy. This concept
should be applied to the PRC-025 standard to align with the direction NERC standard
development is progressing.
Response: The drafting team continues to support the proposed draft standard as
currently structured. The current draft requirements allow Compliance Enforcement
Authorities to take into account an entity’s process in connection with the required
activities. How compliance will approach a standard is appropriate for the

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development of the RSAW. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
North American
Generator Forum
Standards Review
Team

Yes

1. UATs should be dropped from the standard. The Application Guidelines state that
the reliability objective of PRC-025 is to cover, “all load-responsive protective relays
that are affected by increased generator output in response to system disturbances,”
but the relays of UATs are not in this category. A disturbance on the HV system would
not affect the real or reactive power draws of auxiliary loads, and it was stated in the
12/13/2012 webinar that UAT relay trips are not known to have caused the loss of any
generation units during the northeast blackout of ‘03. UATs are stated later in the
Application Guidelines to have been included to satisfy a FERC directive (Order No.
733, paragraph 104), but such a move nonetheless appears to be incorrect, particularly
in light of NERC’s recent emphasis on the cost justification of reliability standards.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
2. The generator overload protection exception added to Draft 3 for extremely inverse
characteristics (5th bull-dot) is a major improvement, but the term “full-load current”
needs clarification. Is this the current at normal full-load turbine output and typical PF,
or the value determined from the generator nameplate MVA at rated voltage, or the
base (no fans, no oil circulation) rating of the GSU?
Response: The drafting team notes that the phrase full load current refers to rated
armature current of the generator. No change made.
3. The exception of comment #2 above, which is presently limited to generator
overloads, could be applied for UATs as well if eliminating this equipment in its entirety

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(per comment #1 above) does not prove feasible.
Response: The exclusion #7 addresses transformers and is not limited to only GSUs. No
change made.
4. PRC-025 should be revised to grandfather existing major equipment, similar to the
approach recently used for PRC-024. It may not always be possible to develop PRC025-conforming means of protection without replacing GSUs or UATs; and, in the
absence of any compensation to the owner, it would be inappropriate to outlaw
equipment that was acceptable under the rules in effect at the time it was installed.
Response: The drafting team contends that it is possible to provide phase fault backup
protection while meeting the requirements of this standard. The drafting team notes
that the standard provides multiple options for setting transformer load-responsive
phase relays to address this concern. If legacy approaches do not allow the entity to
meet the requirement and protection objectives, other approaches may be necessary.
To prevent equipment damage from excessive time exposed to overload conditions,
the drafting team has included exclusions for dedicated generator and transformer
overload protection that operates in time frames appropriate to overload protection.
No change made.
5. The applicability of PRC-025 should exclude small gensets that are NERC-registered
solely due to being black start-capable, the tripping of which would not meaningfully
affect the ability of the system to ride through Disturbances. It would be best to allow
such units to maintain their present loadability relay settings, if they are consistent
with a reasonable coordination study, rather than mandate upgrades that augment the
degree to which NERC requirements have already eliminated any economic rationale
for having black-start facilities.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the

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applicability of the standard, they may not perform as expected to facilitate system
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan
(i.e., SRP). No change made.
6. Regarding in particular voltage-restrained overcurrent relays, this type of device is
notorious for not having a predictable operation time under fault conditions. If they
did mis-operate in the August 2003 blackout they should be changed-out rather than
requiring that the settings be set as high as specified in the draft standard.
Response: The drafting team agrees, in general, that these devices are not
recommended and, where used, that these devices should be replaced. However, as
the drafting team is unable to require that such relays be replaced, applicable criteria
are provided. No change made.
7. Deeming any and all violations of this standard to have a high violation risk factor
and a severe violation severity level seems overly harsh, given the compliance
feasibility uncertainties expressed above.
Response: The VRF criteria are based on the risk to the system if a requirement is
violated, and the VSL criteria are based on the degree of non-compliance. Alleged
difficulties in achieving compliance are not a factor in the criteria for either VRFs or
VSLs. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Dominion

Yes

PRC-025 -1 Requirement 1: remove the following words: “...while maintaining reliable
fault protection.” It is not possible for entities to measure or prove this statement.
The wording, “while maintaining reliable fault protection”, is also included in the
Introduction section of PRC-025-1 Guidelines and Technical Basis. The inclusion
“describes that the Generator Owner is to comply with this standard while achieving
its desired protection goals.” Dominion believes that the Generator Owner

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understands the compliance obligation based upon the requirements of the standards
and that the inclusion of the referenced language should be excluded based on the
inability of the entity to measure or provide evidence of maintaining reliable fault
protection.
Response: The drafting team contends that the description of the term “while
maintaining reliable fault protection” found in the Requirement R1 rationale box
adequately conveys the suggested intent. No change made.
PRC-025-1: Redline - Page 6 of 18 Table of Compliance Elements; An indication of
Lower VSL. Moderate VSL or High VSL needs to be determined with regard to R1.
Dominion disagrees with the “all or nothing” approach to VSLs.
Response: The specified VSL applies separately and individually to each protective
relay addressed; therefore it is not possible to grade the VSL.
PRC-023-3 Implementation plan; Redline Pages 3-6, R1-R6 the Requirement wording
(in the Applicability column) does not exactly match the Requirement wording in the
standard. Dominion suggests correcting the wording to match the Standard as written.
Response: The changed suggested is not editorial and is outside the scope of the
supplemental Standards Authorization Request (SAR) as approved by the Standards
Committee on January 18, 2013. No change made.
PRC-025-1 @ figure 3 - Dominion does not necessarily agree that these lines are part of
networked transmission and therefore would not be considered as generator
interconnection Facilities. Dominion believes the designation of the lines should be
based on registration of the asset owner and will be providing supporting comments in
response to the FERC NOPR in docket # RM12-16-000.
Response: The drafting team asserts that the lines in Figure 3 can be expected to carry
network flow, are not used exclusively to export energy directly from a BES generating
unit or generating plant to the network, and therefore are not generator

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interconnection Facilities. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Santee Cooper

Yes

Unit Auxiliary Transformers (UATs) should be removed from this standard (Facilities
Section 3.2.3). The purpose of this standard is “To set load-responsive protective relays
associated with generation Facilities at a level to prevent unnecessary tripping of
generators during a system disturbance for conditions that do not pose a risk of
damage.” The intent as stated in the Application Guidelines is to pertain to relays that
“are affected by increased generator output in response to system disturbances.” UATs
do not fit this criteria. Addressing generating plant unit auxiliary transformers does not
have to translate into creating a standard requirement for that equipment. An
investigation and evaluation of the protection system for unit auxiliary transformers
should be considered by the standard drafting team and deemed to be not related to
generator loadability and fulfill the FERC order to address the subject.

Response: The drafting team thanks you for your comments and contends that the load-responsive protection for any UAT that
supplies “running station power” to the plant, such that tripping of the UAT will cause the generator to trip, should be addressed
by the draft standard. The drafting team has revised the Table 1 criteria for UAT protection in the Standard and the Guidelines
and Technical Basis discussion accordingly. Change made.
JEA

Yes

We would like to see modifications to violation severity levels. While we recognize the
SDT is following NERC binary guidelines “pass/fail”, this needs to be improved. The
idea that either they “applied” or “did not apply” settings must result in a “severe”
violation level does not match the reality that missing 10 out of 20 poses a greater risk
to the BES than 1 out of 100.

Response: The drafting team thanks you for your comments and notes the specified VSL applies separately and individually to
each protective relay addressed; therefore it is not possible to grade the VSL. No change made.

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Bonneville Power
Administration

Yes or No
Yes

Question 5 Comment
Comments:
(1) The use of the term generation interconnection facility without an official definition
of the term is concerning to BPA. BPA believes that this term may have different
meanings between entities. For example, the entire Bulk Electric System (BES)
together with all distribution systems could be considered to be a generation
interconnection facility because the purpose of the BES and distribution systems is to
interconnect generation to the end user (load). Only under the Guidelines and
Technical Basis is a description of what a generator interconnection facility found.BPA
is concerned with this approach as it does not give an official definition, and this
document is not part of the standard. Additionally, BPA believes the description of
generator interconnection facility given in the Guidelines and Technical Basis creates
problems. The description provided is that the generation interconnection facility
consists of elements between the generator step up transformer (GSU) and the
interface with the portion of the BES where the Transmission Owner (TO) takes over
the ownership. In many cases the TO owns the line that connects to the generator
step up (GSU) transformer and there are no elements between the GSU and the TO.
According to this description there is no generation interconnection facility. Due to
the ownership arrangements of transmission, generation, and their interconnection
facilities throughout the country are highly variable, BPA believes it is not suitable to
develop a definition of generation interconnection facilities based on ownership. Such
a definition may reflect the ownership arrangements within a particular region while it
does not take into account various other arrangements that may exist. BPA
recommends for the drafting team to provide a definition of generation
interconnection facility that takes into account the various ownership situations that
may exist.
Response: The drafting team has replaced this term with "Elements that connect a
GSU to the Transmission system and are used exclusively to export energy directly
from a BES generating unit or generating plant." Change made.

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(2) BPA believes the use of the word associated in the purpose statement of PRC-025-1
as well as in Section 3.2 Facilities is too vague and recommends this term be changed
to “whose function is the protection of generation Facilities...” in the purpose
statement and Section 3.2 be rewritten to read “3.2 Facilities: The following Bulk
Electric System Elements, including those generating units and generating plants
identified as Blackstart Resources in the Transmission Operator's system restoration
plan:”
Response: The Purpose statement was modified in the last draft to not be generator
specific. The standard addresses generation Facilities in general and the criteria
provide reasonable loadability settings that are within the capability of the equipment
the standard is addressing. The purpose statement has been modified to clarify risk to
associated equipment. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Tennessee Valley
Authority

Yes

Is the intent of this standard to identify the lines in their normal configuration and not
for contingency events? For example, referring to Figure 3 from the Webinar, if a line
is lost, causing the system configuration to change to what is shown in Figure 1, does
this mean that the configuration then is considered to fall under R7?

Response: The drafting team has decided to integrate Transmission Owner and Distribution Provider into the proposed PRC-0251, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a bright line between the two standards.
The owner of load-responsive protective relays applied to generation-related Facilities will be in PRC-025 and owner of loadresponsive protective relays network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change made.
The intent of the standard is based on lines in the normal configuration as being presented in the Figures. No change made.
ACES Standards
Collaborators

Yes

(1) We are not convinced that applicability of PRC-023 R7 and R8 to a Distribution
Provider is necessary. It would be unusual for a generator that meets BES definition
criteria and compliance registry criteria to be connected to a Distribution Provider.

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Both criteria require a single generator to be 20 MVA or a plant site to be 75 MVA.
From a practical perspective, this could actually be a detriment to reliability by
distracting the Distribution Provider from reliability activities because they have to
focus on documenting that they do not have any applicable generators connected.
How does including the Distribution Provider as an applicable entity benefit reliability?
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement R7
and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
Even though it may be unlikely that such a Facility would be connected to a
Distribution Provider, the drafting team contends that providing for such a condition in
PRC-025-1 would assure that no gaps exist for this situation.
(2) The High VRFs for PRC-023 R7 and R8 and PRC-25 R1 and R2 are inconsistent with
established NERC criteria. In order to meet the High criteria, a single violation of the
requirement “could directly cause or contribute to bulk electric instability, separation
or a cascading sequence of failures.” A single failure to have a relay set to avoid
loadability concerns on a single generator could not lead to instability, separation or
cascading without violating other standards. For example, TOP-004-2 R2 already
require N-1 operation so a single generator tripping due to relay loadability issues
would require at least two standards requirements violations. This cannot be viewed
as “directly” causing.
Response: The drafting team contends that the High VRF is correct, as it fully satisfies
the associated criteria from the VRF Guidelines, “… 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

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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,
…” Please note that the above criteria include emergency and abnormal conditions
under which a loss of a generator that does not meet the loadability requirements
could lead to one of these consequences. No change made.
(3) We believe the VSLs for PRC-023 R7 and R8 and PRC-25 R1 and R2 are written
inconsistent FERC guideline 3 which states that the VSL cannot change the
requirement. The plain language of the requirements is written in a plural format as
though the requirement considers all relays are considered simultaneously. The VSLs
are written such that each relay that is not set appropriately is a separate violation.
The VSLs, in essence, change the requirements. For example, the Requirement for
PRC-023 R7, states “shall set their load responsive relays,” while the VSL essentially
modifies the requirement to state “shall set each load responsive relay.” We
recommend modifying the VSL to be in better alignment with the requirement.
Response: PRC-025-1 has only one Requirement R1 (not R2) which applies separately
and individually to each protective relay (singular) addressed; therefore it is not
possible to grade the VSL. No change made.
The drafting team has decided to integrate Transmission Owner and Distribution
Provider into the proposed PRC-025-1, rather than adding Requirement R7 and R8 to
the proposed PRC-023-3 to establish a bright line between the two standards. The
owner of load-responsive protective relays applied to generation-related Facilities will
be in PRC-025 and owner of load-responsive protective relays network-related
Facilities in PRC-023 regardless of ownership of the Facilities. In removing
Requirements R7 and R8 from PRC-023-3, the plural use of “relays” is no longer
relevant. Change made.
(4) The wording in the second sentence of the second paragraph in PRC-023
Attachment C needs to be fixed. There seems to be an extra “Facilities.”

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Question 5 Comment
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement R7
and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
Attachment C and its Table 1 have been eliminated. The comment is no longer
relevant; however, the drafting team updated the similar occurrence in the PRC-025-1
Attachment 1 to “Elements” which more correctly identifies those Facilities which are
subject to the standard. Change made.
(5) RRO is used throughout both standards. It should be Regional Entity, as stated in
NERC’s legal memorandum on the “Use of ‘Regional Reliability Organization’...” The
memo states that in general, drafting teams can replace “RRO” with “RE,” provided the
functions being performed by the RE are related to their delegated duties. Reliability
Standards that refer to REs are legally binding on the REs by operation of Rule 100 of
NERC’s Rules of Procedure and by the delegation agreements that NERC has entered
into with each RE.
Response: The reference to “…or other entity as specified by the Regional Reliability
Organization (RRO)” has been removed from the standard. Change made.
(6) Please strike “other entity as specified by the Regional Reliability Organization
(RRO)” that is used throughout Attachment C in PRC-023 and Attachment 1 in PRC-025.
It creates compliance uncertainty and provides the Regional Entity far too much
discretion. If the purpose is an attempt to document from other standards where the
nameplate rating is communicating, we suggest that the drafting team perform a
search of the other standards and explicitly document the entities. Otherwise, the
Regional Entity, as the standard is worded, could simply decide to move the dates.

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Question 5 Comment
FERC has ordered NERC to remove regional discretion from standards development,
such as the revision of the BES definition.
Response: The reference to “…or other entity as specified by the Regional Reliability
Organization (RRO)” has been removed from the standard. Change made.
(7) We appreciate the relay elements that are identified for exclusion in PRC-023
Attachment C. However, we believe that the exclusion should be identified explicitly in
Attachment A as well. Attachment A is referenced in applicability section. We are
concerned since attachment C is not referenced in the applicability section that
exclusion of the relay elements could be lost.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement R7
and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.
In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
Attachment C and its Table 1 have been eliminated. Change made.
(8) We disagree with the applicability of 3.2.5. We not understand how applicability
to a distribution collector system for dispersed generation benefits reliability. If a
subset of generators in the dispersed generation site trip, it will be a small amount of
MWs lost that would not impact the reliability of the Bulk Power System. We can
understand inclusion of the main GSU for a large site but not the individual collector
elements.
Response: The drafting team intends that the Applicability for Facilities associated with
aggregated generation aligns with the definition of the BES. The drafting team notes
that all feeders and individual generators within an aggregated site will require similar

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Question 5 Comment
load-responsive protective relay settings because they will be challenged by the same
loadability during the system conditions being addressed by PRC-025-1; therefore, they
will respond as a group, emphasizing that the criteria needs to be applied throughout
the aggregated Facility. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
AESI Inc.

Yes

This draft of the standard uses 0.85 pu transmission system voltage as a benchmark for
determining the settings. The latest version of PRC-024-1 defines post-disturbance
voltage profile where the system voltage is below 0.85 pu up to 3 seconds. Is there a
need to take that into consideration for this standard.

Response: The drafting team has coordinated the concern with the generation verification standard drafting team working on
PRC-024-1 under Project 2007-09. The result was that load-responsive protective relay functions (i.e., “…impedance relays,
voltage controlled overcurrent relays…”) were removed from the PRC-024-1 standard in footnote 1. No change made.
Chelan County PUD

Yes

1. Please, reconsider the applicaiton to small units that are "black start" or auxiliary
units in a BES plant. Application of these requirements to a small (750kW) hydro unit
that is black start is problamatic particularly due to the age of many of these units. It is
difficult to see where loss of a unit of small size would impact the BES during this type
of event. Please, consider a minimum size threshold for units where these
requirements would be applicable. Perhaps 20MW as is used in the BES definition
would be appropirate. Consider also an exclusion for a small unit, say less than 5MW,
that is part of an aggregate plant of larger units that exceeds the 75MW plant
threshold. An example is our 750kW hydro unit that is in the plant with ten 25MW
units. It seems excessive to apply this to the 750kW unit.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the
applicability of the standard, they may not perform as expected to facilitate system

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Question 5 Comment
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan
(i.e., SRP). No change made.
The applicability is consistent with the definition of the BES. No change made.
2. UATs should be dropped from the standard. The Application Guidelines state that
the reliability objective of PRC-025 is to cover, “all load-responsive protective relays
that are affected by increased generator output in response to system disturbances,”
but the relays of UATs are not in this category. A disturbance on the HV system would
not affect the real or reactive power draws of auxiliary loads, and it was stated in the
12/13/2012 webinar that UAT relay trips are not known to have caused the loss of any
generation units during the northeast blackout of ‘03. UATs are stated later in the
Application Guidelines to have been included to satisfy a FERC directive (Order No.
733, paragraph 104), but such a move nonetheless appears to be incorrect, particularly
in light of NERC’s recent emphasis on the cost justification of reliability standards.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
3. Clarify UAT and station service transformers. Footnote 1 says "Loss of these
transformers will result in removing the generator from service." Does that mean it
only applies to SS transformers that loss of will remove a unit from service? What
about provisions for backup, multiple transformers and busses? Consider an hydro
plant with 4 sation service busses and 12 generating units. Would this standard apply
to all? This is very different from thermal stations where a unit would have a
dedicated transformer that without its power the unit will trip. Consider liminting this
only to transformers where loss would cause a direct trip of a BES unit, or eleminiate

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Question 5 Comment
UAT ans SS transformers completely per comment 2.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
4. The generator overload protection exception added to Draft 3 for extremely inverse
characteristics (5th bull-dot) is a major improvement, but the term “full-load current”
needs clarification. Is this the current at normal full-load turbine output and typical PF,
or the value determined from the generator nameplate MVA at rated voltage, or the
base (no fans, no oil circulation) rating of the GSU, or FERC hydro nameplate criteria at
best gate?
Response: The drafting team notes that the phrase full load current refers to rated
armature current of the generator. No change made.
5. PRC-025 should be revised to grandfather existing major equipment, similar to the
approach recently used for PRC-024. It may not always be possible to develop PRC025-conforming means of protection without replacing GSUs or UATs; and, in the
absence of any compensation to the owner, it would be inappropriate to outlaw
equipment that was acceptable under the rules in effect at the time it was installed.
Response: The drafting team contends that it is possible to provide phase fault backup
protection while meeting the requirements of this standard. The drafting team notes
that the standard provides multiple options for setting transformer load-responsive
phase relays to address this concern. If legacy approaches do not allow the entity to
meet the requirement and protection objectives, other approaches may be necessary.
To prevent equipment damage from excessive time exposed to overload conditions,
the drafting team has included exclusions for dedicated generator and transformer
overload protection that operates in time frames appropriate to overload protection.

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Question 5 Comment
No change made.
6. Deeming any and all violations of this standard to have a high violation risk factor
and a severe violation severity level seems overly harsh, given the compliance
feasibility uncertainties expressed above. Consider a VSL based on the size of the
generating unit or amount of generation that would be lost if the standard were not
properly applied. A 20MVA unit would have a much lower impact on the reliability of
the BES than a 500MW unit.
Response: The drafting team contends that the High VRF is correct, as it fully satisfies
the associated criteria from the VRF Guidelines, “… 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,
…” Please note that the above criteria include emergency and abnormal conditions
under which a loss of a generator that does not meet the loadability requirements
could lead to one of these consequences. The drafting team also contends that a High
VSL is appropriate, in that PRC-025-1 R1 applies separately and individually to each
protective relay addressed; therefore it is not possible to grade the VSL; therefore the
VSL is binary regardless of the size of the generating unit. No change made.
The drafting team contends that the requirements proposed within PRC-025-1 satisfy
the associated FERC directive and are appropriate and necessary. Appendix 4B, Section
2 of the NERC Rules of Procedures identify and discuss the basic principles
underpinning why and how NERC and the Regional Entities will determine Penalties,
sanctions, and Remedial action Directives for violations of the Requirements of the
Reliability Standards. By being classified as BES, the facilities involved have been
determined to have impact on the reliability of the BES. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.

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Western Farmers
Electric Cooperative

Yes or No

Question 5 Comment

Yes

Many generation Facilities, that are part of the Bulk Electric System, became
commercial in the 1950’s, 1960’s, 1970’s, 1980’s and 1990’s. These Facilities should be
Grandfathered in. Many of these units, although reliable, it may not be cost effective
to obtain compliance with PRC-025-1. Many of these Facilities would be forced to
either:
(1) implement very expensive upgrades to existing equipment,
(2) replace existing equipment,
(3) retire the Facility.
It’s my opinion this is not consistent with the economic rational NERC is attempting to
achieve.
Response: The drafting team contends that it is possible to provide phase fault backup
protection while meeting the requirements of this standard. The drafting team notes
that the standard provides multiple options for setting transformer load-responsive
phase relays to address this concern. If legacy approaches do not allow the entity to
meet the requirement and protection objectives, other approaches may be necessary.
To prevent equipment damage from excessive time exposed to overload conditions,
the drafting team has included exclusions for dedicated generator and transformer
overload protection that operates in time frames appropriate to overload protection.
No change made.
Secondly, the Violation Risk Factor of High, seems extreme because several other
standards address generator reliability (Under-frequency, Misoperations, Protection
System Maintenance and Testing, Generator Verification). These standards, have
resulted in many generation Facilities having undergone relay coordination studies to
prevent an occurrence similar to the 2003 “blackout.”
Response: These other standards do not address the conditions being addressed by
this standard. No change made.

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Yes or No

Question 5 Comment

Response: The drafting team thanks you for your comments; please see the above responses.
Xcel Energy

Yes

1) Applicability: In the applicability sections, we suggest you replace the phrase "BES
generating unit or generating plant" with "BES generating unit or BES generating plant"
to be more clear.
Response: The drafting team contends that the adjective, “BES” clearly applies to both
the generating unit and the generating plant. No change made.
2) M1: We recommend you add “simulation results” as acceptable evidence in
Measure M1. (reason: Some people may choose to do PRC023 check in the CAPE
simulation.)
Response: This is existing approved content within PRC-023-2 and outside the scope of
this project. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Manitoba Hydro

Yes

(1) Section 3.1.1, PRC-025-01 - the repeated word “Facilities” seems unnecessary. For
clarity, remove the last instance of the word “Facilities” in the statement: “Generator
Owner that applies load-responsive protective relays at the terminals of Facilities listed
in 3.2, Facilities.”
Response: The first occurrence of Facilities should have been “Elements” to refer to
the numbered list under the section 3.2, Facilities. Change made.
(2) Section 3.2 - it would be useful to add criteria that define which generator units
should be included as associated with the BES. Alternatively, should this standard
refer to the BES definition for which generator units in this standard will apply to?
Response: This standard includes all generating units and generating plants that are
part of the BES, as established by application of the approved definition of Bulk Electric
System (BES). No change made.

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Question 5 Comment
(3) Section 3.2.5 - It is unclear what elements should be included in this section Collector lines only? What size (MVA) of generating source that the collector line has
to be on to qualify as one of these elements?
Response: The drafting team intends that the Applicability for Facilities associated with
aggregated generation aligns with the definition of the BES. The drafting team notes
that all feeders and individual generators within an aggregated site will require similar
load-responsive protective relay settings because they will be challenged by the same
loadability during the system conditions being addressed by PRC-025-1; therefore, they
will respond as a group, emphasizing that the criteria needs to be applied throughout
the aggregated Facility. No change made.
(4) Implementation Plan, PRC-023-3 - it would be helpful to include the
implementation plan within the standard
Response: The Implementation Plan is posted as a separate document with supporting
information for industry consideration. Generally, once the standard is NERC Board of
Trustees adopted, the effective date information is re-inserted into the standard;
however, an entity should always consult the implementation plan for additional
information. No change made.
(5) PRC-023-3, Purpose - suggest re-wording to the following “...not interfere with a
system operators ability to take remedial action to protect system reliability....”.
Response: The changed suggested is not editorial and is outside the scope of the
supplemental Standards Authorization Request (SAR) as approved by the Standards
Committee on January 18, 2013. No change made.
(6) PRC-023-3, Purpose - capitalize “system operator” because it appears in the
Glossary of Terms.
Response: Capitalizing a term in the standard to represent the NERC Glossary defined
term introduces the need for additional technical and industry vetting and is not

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Question 5 Comment
editorial.
The changed suggested is not editorial and is outside the scope of the supplemental
Standards Authorization Request (SAR) as approved by the Standards Committee on
January 18, 2013. No change made.
(7) PRC-023-3, Applicability, Functional Entity - capitalize “protection system” because
it appears in the Glossary of Terms.
Response: Capitalizing a term in the standard to represent the NERC Glossary defined
term introduces the need for additional technical and industry vetting and is not
editorial.
The changed suggested is not editorial and is outside the scope of the supplemental
Standards Authorization Request (SAR) as approved by the Standards Committee on
January 18, 2013. No change made.
(8) PRC-023-3, 4.2.1.3 - ‘BES’ should be written Bulk Electric System (BES) since it is the
first appearance of the word.
Response: The drafting team added exclusion text to the Applicability section 4.2.1.1
which occurs before the above referenced section 4.2.1.3; therefore, the BES acronym
has been more fully listed as “Bulk Electric System (BES)” in section 4.2.1.1 rather than
4.2.1.3. Change made.
(9) PRC-023-3, 4.2.3.1 - should Transmission lines be written “Transmission lines (and
paths)”?
Response: Making such a change introduces the need for additional technical and
industry vetting and is not editorial.
The changed suggested is not editorial and is outside the scope of the supplemental
Standards Authorization Request (SAR) as approved by the Standards Committee on
January 18, 2013. No change made.

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Question 5 Comment
(10) PRC-023-3, R1, 4 - capitalize the words “power transfer capability” because it
appears in the Glossary of Terms.
Response: This phrase is not a NERC Glossary term and perhaps it is being confused
with “Total Transfer Capability” (TTC). No change made.
(11) PRC-023 and PRC-025 - capitalize the words “transmission lines” throughout the
document(s).
Response: Capitalizing a term in the standard to represent the NERC Glossary defined
term introduces the need for additional technical and industry vetting and is not
editorial.
The changed suggested is not editorial and is outside the scope of the supplemental
Standards Authorization Request (SAR) as approved by the Standards Committee on
January 18, 2013. No change made.
The phrase “transmission lines” is not used in the proposed PRC-025-1.
(12) PRC-023 and PRC-025, D. Compliance 1.1 - the paraphrased definition of
‘Compliance Enforcement Authority’ from the Rules of Procedure is not the standard
language for this section. Is there a reason that the standard CEA language is not being
used?
Response: The language used in the standard in section D. Compliance 1.1,
“Compliance Enforcement Authority” is the exact definition taken directly from the
NERC Rules of Procedure, Appendix 2, Definitions Used in the Rules of Procedure
effective March 5, 2013. No change made.
(13) PRC-023-3 - Attachment B, Circuits to Evaluate - replace the acronym “BES” with
the words “Bulk Electric System”.
Response: Change made.
(14) PRC-023-3 - Attachment B, Criteria, B2 - write out the words for “IROL” then use

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Question 5 Comment
the acronym thereafter.
Response: Change made.
(15) PRC-023-3 - Attachment C - use the acronym “RRO” after the first instance of the
words “Regional Reliability Organization”.
Response: In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
Attachment C and its Table 1 have been eliminated; therefore the comment is no
longer relevant. Change made.
The reference to “…or other entity as specified by the Regional Reliability Organization
(RRO)” has been removed from the standard. Change made.
(16) PRC-025-1 - Attachment 1: Relay Settings - use the acronym “RRO” after the first
instance of the words “Regional Reliability Organization”.
Response: The reference to “…or other entity as specified by the Regional Reliability
Organization (RRO)” has been removed from the standard. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
ReliabilityFirst

Yes

1) In Attachment 1, it is not clear that the fifth bulleted exception regarding protection
systems that detect generator overloads needs or should be as specific as to cite the 7
seconds at 218% of full-load current operating point or characteristic curve. Typically
for a fault right on the generator terminals, the current decays in a couple of seconds
to around full load current even with the AVR in service. Even during field forcing, it is
more likely that the field overcurrent relay would operate rather than a generator
overload relay. Therefore, the exclusion does not appear to be needed. If the
exclusion is needed, it is recommended that the exclusion be stated in a more general
way such as the following: Protection systems that detect generator overloads that
are designed to coordinate with the generator short-time capability by utilizing a relay
characteristic set to operate no faster than the capability curve and supervised to

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Question 5 Comment
prevent operation below 115% of full-load current.
Response: Generator thermal overload protection may be provided by an overcurrent
relay as described in clause 4.1.1.2 of IEEE standard C37.102-2006, IEEE Guide for AC
Generator Protection. This application must be coordinated with the generator thermal
capability and would be in conflict with PRC-025-1 unless this exclusion is provided.
The drafting team notes that the specific values in exclusion 6 describe a boundary for
setting this protection consistent with the generator short time capability and is not
prescriptive. No change made.
2) The word ‘Each’ appears to be missing in Requirement R8 of PRC-023-3. ‘Each’
should be inserted at the beginning of the requirement before Transmission Owner
and Distribution Provider.
Response: The comment is no longer relevant because the drafting team has decided
to integrate Transmission Owner and Distribution Provider into the proposed PRC-0251, rather than adding Requirement R7 and R8 to the proposed PRC-023-3 to establish a
bright line between the two standards. The owner of load-responsive protective relays
applied to generation-related Facilities will be in PRC-025 and owner of loadresponsive protective relays network-related Facilities in PRC-023 regardless of
ownership of the Facilities. Change made.
3) Since there are cases where redundant UATs that allow a generator to continue to
remain in service when one UAT trips, this may be rationale to revise 3.2.3 of the
Applicability section to indicate exclusion for these configurations. Alternatively, it
could be addressed in the Guidelines and Technical Basis document.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.

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Question 5 Comment
4) The Regional Reliability Organization (RRO) is referenced within both standards and
it was ReliabilityFirst’s understanding that the term RRO was to be removed from all
the standards. In Order 693, Paragraphs 146-148 and paragraph 157 state “The
Commission adopts the NOPR proposal to eliminate references to the regional
reliability organization as a responsible entity in the Reliability Standards. We conclude
that this approach is appropriate because, as explained in the NOPR, such entities are
not users, owners or operators of the Bulk-Power System. NERC indicates that it can
remove such references, except that the Regional Entity should be identified as the
compliance monitor where appropriate.” ReliabilityFirst suggests replacing the RRO
with the Planning Coordinator (PC) or other registered function the SDT determines to
have the wide area view and be responsible for determining what these settings and or
values should be.
Response: The reference to “…or other entity as specified by the Regional Reliability
Organization (RRO)” has been removed from the standard. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Ameren

Yes

(1) The generator overload protection exception on page 8 for “extremely inverse
characteristics” (5th bullet-dot) is a major improvement, but we believe that the term
“full-load current” needs clarification. We ask the SDT, is this current at 100% of the
gross MW capability reported to the TP, or the value determined from the generator
nameplate MVA at rated voltage, or the base (no fans, no oil circulation) rating of the
GSU or the smallest of these?
Response: The drafting team notes that the phrase full load current refers to rated
armature current of the generator. No change made.
(2) We believe that Blackstart Resources should be excluded because there is no
technical basis for including them. On the contrary, it is more important to assure
Blackstart Resources are adequately protected and available for restoration in the

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extremely unlikely event that a wide-area blackout occurs. Also, we believe that there
is no evidence that the tripping of a Blackstart Resources has contributed to
widespread outages. In our experience, these resources are below the 20MVA
threshold and even if they were on-line and tripped their impact to the BES are
minimal.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the
applicability of the standard, they may not perform as expected to facilitate system
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan
(i.e., SRP). No change made.
(3) In addition to our comments, we also agree with the SERC Protection & Control
Subcommittee (PCS) comments and include them by reference.
Response: Please see the responses to the SERC PCS comments.

Response: The drafting team thanks you for your comments; please see the above responses.
American Electric
Power

Yes

System fed auxiliary transformers whose loss would not result in an instantaneous
generating unit trip, and for which operators would have opportunity to reconfigure
the plant auxiliary load before a unit trip occurs, should be excluded from this
standard. However, if the SDT intends the standard to be applicable to all system fed
auxiliary transformers, we recommend removing the text “...that trips the generator
either directly or via an interposing/lockout relay” from the standard. This statement is
similar to language that entities have used to exclude system fed auxiliary
transformers that initiate a process shutdown trip from the scope of other NERC PRC
standards.
During a disturbance in which system voltage becomes depressed, the generator will

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Question 5 Comment
respond by increasing excitation in an effort to compensate for the voltage loss. This
will result in the generator terminal voltage being greater than the system voltage. For
this reason, AEP recommends that settings for applicable relays installed on the
generator side of the GSU be based on a generator bus voltage of 1.0 per unit at the
generator terminals, rather than a generator bus voltage calculated from 0.85/0.95 per
unit of the GSU high-side nominal voltage.

Response: The drafting team contends that the load-responsive protection for any UAT that supplies “running station power” to
the plant, such that tripping of the UAT will cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the Guidelines and Technical Basis discussion
accordingly. Change made
The drafting team acknowledges that the generator terminal voltage during field-forcing will be higher than the transmission
system voltage; the drafting team accounted for this in the voltage criteria. No change made.
Tacoma Power

Yes

Comments 1-4 below pertain to PRC-025-1.
1. Referring to Attachment 1, are phase fault detectors used in current-based local
breaker failure schemes excluded from PRC-025-1?
Response: Yes. The breaker failure relay will assert only if other components fail and is
not addressed in the standard; therefore, the associated fault detector is not included.
No change made.
2. Referring to Attachment 1, Footnote 3 still has the terms “no-load tap changers
(NLTC)” and “on-load tap changers (OLTC).”
Response: Change made.
3. Referring to page 22 of 68 of the redlined Guidelines and Technical Basis, the first
paragraph after “Generator Interconnection Facilities (Synchronous Generators) Phase
Distance Relays - Directional Toward Transmission System (21) (Options 14a and 14b),”
change “...for these relay...” to “...for these relays...” (There are also other instances of

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this issue.)
Response: The editorial suggestion is correct. Change made.
4. Referring to page 20 of 68 of the redlined Guidelines and Technical Basis, would the
UATs shown in Figure 6 necessarily be applicable to PRC-025-1? It seems that phase
time overcurrent relays applied to UATs like these might not “act to trip the generator
directly or via lockout or auxiliary tripping relay.”
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
5. Referring to Attachment C, why are only two of the bulleted exceptions shown in
PRC-025-1 Attachment 1 brought over?
Response: In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
Attachment C and its Table 1 have been eliminated. Change made.
6. Referring to page 12 of 13 of the redlined Implementation Plan, change “...were
added to address to situations...” to “...were added to address situations...”
Response: In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
the Implementation Plan has been revised to note the specific milestones that are
known to improve clarity. Change made.
7. Referring to page 13 of 13 of the redlined Implementation Plan, last row in the
table, are references to R7 supposed to be references to R8? Additionally, change
“...equally and efficient...” to “...equally efficient...”
Response: In removing the previously proposed Requirements R7 and R8 in PRC-023-3,
the Implementation Plan has been revised to note the specific milestones that are

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known to improve clarity. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Tri-State G&T

Yes

1. UATs should be dropped from the standard. The Application Guidelines state that
the reliability objective of PRC-025 is to cover, “all load-responsive protective relays
that are affected by increased generator output in response to system disturbances,”
but the relays of UATs are not in this category. A disturbance on the HV system would
not affect the real or reactive power draws of auxiliary loads, and it was stated in the
12/13/2012 webinar that UAT relay trips are not known to have caused the loss of any
generation units during the northeast blackout of ‘03. UATs are stated later in the
Application Guidelines to have been included to satisfy a FERC directive (Order No.
733, paragraph 104), but such a move nonetheless appears to be incorrect, particularly
in light of NERC’s recent emphasis on the cost justification of reliability standards.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
2. PRC-025 should be revised to grandfather existing major equipment, similar to the
approach recently used for PRC-024. It may not always be possible to develop PRC025-conforming means of protection without replacing GSUs or UATs; and, in the
absence of any compensation to the owner, it would be inappropriate to outlaw
equipment that was acceptable under the rules in effect at the time it was installed.
Response: The drafting team contends that it is possible to provide phase fault backup
protection while meeting the requirements of this standard. The drafting team notes
that the standard provides multiple options for setting transformer load-responsive
phase relays to address this concern. If legacy approaches do not allow the entity to

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meet the requirement and protection objectives, other approaches may be necessary.
To prevent equipment damage from excessive time exposed to overload conditions,
the drafting team has included exclusions for dedicated generator and transformer
overload protection that operates in time frames appropriate to overload protection.
No change made.
3. The applicability of PRC-025 should exclude small gensets that are NERC-registered
solely due to being black start-capable, the tripping of which would not meaningfully
affect the ability of the system to ride through Disturbances. It would be best to allow
such units to maintain their present loadability relay settings, if they are consistent
with a reasonable coordination study, rather than mandate upgrades that augment the
degree to which NERC requirements have already eliminated any economic rationale
for having black-start facilities.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the
applicability of the standard, they may not perform as expected to facilitate system
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan
(i.e., SRP). No change made.
4. Regarding in particular voltage-restrained overcurrent relays, this type of device is
notorious for not having a predictable operation time under fault conditions. If they
did mis-operate in the August 2003 blackout they should be changed-out rather than
requiring that the settings be set as high as specified in the draft standard.
Response: The drafting team agrees, in general, these devices are not recommended,
and where used, that these devices should be replaced. However, as the drafting team
is unable to require that such relays be replaced, applicable criteria are provided. The
threshold criteria in PRC-025-1 are necessary to prevent tripping from generator loadresponsive protective relays for short-time overloads during the field-forcing

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conditions of the generator, for which the equipment was designed. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Ingleside
Cogeneration LP

Yes

In the previous posting, the project team requested our estimated compliance costs
and comments on the RSAW. Both of these projects are components of risk-based
compliance - which Ingleside Cogeneration LP fully supports. However, it appears that
these are not considerations at all in the latest postings.
We are not sure what has changed in the intellectual basis of risk-based compliance,
but it seems we have taken a step backwards. The rationale for far too many of the
project team’s consideration of comments was that FERC Order 733 mandated some
action. Since FERC has been generally supportive of the risk-based initiative, this type
of response is inconsistent with their position in our view.

Response: The Cost Effective Analysis Process (CEAP) in the draft 3 posting of PRC-025-1 was an initial pilot of the program for
only Phase II of the CEAP. The drafting team was provided summary information which did not reveal substantive reasons for
changing the way the team developed PRC-025-1. Please see the Pilot CEAP Report on the Project 2010-13.2 project page
(http://www.nerc.com/pa/Stand/Pages/Project-2010-13-2-Phase-2-Relay-Loadability-Generation.aspx). No change made.
Also, NERC Compliance provided the industry comments to the drafting team from the RSAW which was posted
contemporaneously with the draft 3 posting of PRC-025-1. Revisions made to the RSAW were provided to NERC Compliance for
consideration and reposting; however, NERC Compliance elected to wait as they are currently working toward a more defined
process for RSAW posting and commenting. No change made.
Entergy Services, Inc.
(Transmission)

Yes

The implementation plan may be challenging to meet and an alternative
implementation plan may need to be provided based on the population of loadresponsive protective relays determined affected by this standard and the subset of
which that will require replacement relays. Additional resources will be required to
(1) determine the population of load-responsive relays at each generating station,

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(2) determine the settings of the existing load-responsive relays,
(3) calculate load-responsive relay settings per the reliability standard,
(4) compare the existing load-responsive relay settings to the calculated loadresponsive relay settings to determine the population which are acceptable as-is, the
population that require a settings change, and the population that requires
replacement,
(5) schedule the population of load-responsive relays for settings change,
(6) order replacement load-responsive relays for the population determined incapable
of meeting the reliability standard and schedule relay replacement. The resulting
calculations and set-point datasheets will form the basis for the load-responsive relay
settings and evidence for meeting the standard’s requirements.

Response: The drafting team thanks you for your comments and contends that the Implementation Plan establishes the
deadlines by which the standards must be implemented. Individual steps to achieve implementation are left to the entity to
determine and manage. No change made.
Public Service
Enterprise Group

Yes

The SDT needs to confirm that UATs that are energized from the system (not the GSU)
at high-side voltages that are below 100 kV are part of the BES before imposing
standards on UAT load-responsive relay settings.

Response: The drafting team thanks you for your comments and notes that NERC Reliability Standards may be applicable to
equipment that is not part of the BES if necessary to support reliable operation of the bulk power system. No change made.
Seminole Electric
Cooperative Inc.

Yes

Seminole Electric reasons that the NERC SDT has not provided sufficient evidence to
warrant a High VRF and a Severe VSL for penalties associated with proposed Standard
PRC-025-1.

Response: The drafting team contends that the High VRF is correct, as it fully satisfies the associated criteria from the VRF

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Guidelines, “… 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, …” Please note that the above criteria include emergency and abnormal conditions under which a loss of a
generator that does not meet the loadability requirements could lead to one of these consequences. The drafting team also
contends that a High VSL is appropriate, in that PRC-025-1 R1 applies separately and individually to each protective relay
addressed; therefore it is not possible to grade the VSL. No change made.
Flathead Electric
Cooperative

Yes

Do not support including Elements utilized in the aggregation of dispersed power
producing resources. This seems to have the potential to rope very small generators
into significant compliance burdens for very little reliability benefit.

Response: The drafting team intends that the Applicability for Facilities associated with aggregated generation aligns with the
definition of the BES. The drafting team notes that all feeders and individual generators within an aggregated site will require
similar load-responsive protective relay settings because they will be challenged by the same loadability during the system
conditions being addressed by PRC-025-1; therefore, they will respond as a group, emphasizing that the criteria needs to be
applied throughout the aggregated Facility. No change made.
Southwest Power
Pool

Yes

For the sake of clarity, I would suggest adding the phrase ‘to the generator’ at the end
of the Purpose of PRC-025-1. This is implied in the existing language but it wouldn’t
hurt to add this and specifically indicate what damage you’re referring to.
Response: The Purpose statement was modified in the last draft to not be generator
specific. The standard addresses generation Facilities in general and the criteria
provide reasonable loadability settings that are within the capability of the equipment
the standard is addressing. The purpose statement has been modified to clarify risk to
associated equipment. Change made.
For consistency within the requirements and between the requirement and
corresponding measure in this situation, please add ‘Each’ at the beginning of
Requirement R8. This makes R8 consistent with the rest of the requirements and with

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Measure M8.
Response: The drafting team has decided to integrate Transmission Owner and
Distribution Provider into the proposed PRC-025-1, rather than adding Requirement R7
and R8 to the proposed PRC-023-3 to establish a bright line between the two
standards. The owner of load-responsive protective relays applied to generationrelated Facilities will be in PRC-025 and owner of load-responsive protective relays
network-related Facilities in PRC-023 regardless of ownership of the Facilities. Change
made.

Response: The drafting team thanks you for your comments; please see the above responses.
Kansas City Power
and Light

Yes

Generators and Generator step up transformers are critical elements of the BES and
have very long lead times for replacement or major repair. However, the Transmission
Relay load ability standard has less stringent load ability requirements than the
Generator load ability standard. Transmission lines are allowed to trip at 150% of four
hour rating or 115% of 15 minute rating. We do not understand the newly added
portion of the Exceptions of PRC-025-1 why is there only the option of a specific curve
type specified for the Generator. There is no exception available for the GSU or Aux
Transformers therefore the GSU and Aux transformers that would allow them to be set
like large auto transformers it is not our belief that these transformers should be
required to be set with more Stringent settings. We believe that these transformers
should be set similar to the large auto transformers.

Response: The drafting team thanks you for your comment and notes that Exclusion #7 addresses transformers and is not limited
to only GSUs. No change made.
This exclusion is different than Exclusion #6 (applicable to generators) to reflect the differences in thermal overload capability.
The drafting team asserts the time frames in these exclusions are therefore appropriate. No change made.
MRO NERC Standards

The NSRF remains concerned that the proposed calculations for the distance relays will

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adversely affect reliability of the BES by requiring generators to pull back distance
reaches too far which could lead to reduced rely coverage (at least for backup relaying)
or longer delays for coordination. Some sample calculations performed by NSRF
members show that distance reaches need to be pulled back more than 30%. The
NSRF members believe that this is most likely due to the more conservative relay load
limit angle calculations at 30 degrees rather than former MidContinent Area Power
Pool (MAPP) criteria which used line Maximum Torque Angle calculations which
typically averaged near 70 - 85 degrees. Sample MAPP Relay Load Limit Calculation:
(0.85*kV)^2 / (Z1max*cos(max torque angle - line power factor angle)NSRF sample
calculations show that many generators may require 21 distance setting changes based
upon this proposed standard, potentially resulting in potential reductions of relay
backup coverage for lines leaving some generating stations. This will put a much
higher risk and responsibility on the TO too have extremely reliable protection for the
lines. We will no longer be able to trip the generator off in a backup mode if the TO
does not clear the phase fault at end of line. This appears to conflict with R1, unless
the standard is mandating the installation of additional equipment such as redundant
relays systems to maintain reliable fault protection.
The NSRF would ask the NERC Standard drafting team to work with NSRF members to
help verify the basis for the new calculations and if this does in fact reduce relay
coverage or require entities to install additional relaying to maintain system reliability
as mandated in R1.

Response: The drafting team thanks you for your comments and notes the basis for the calculations for the generator protective
relays in proposed PRC-025-1 is well established by observed behavior during disturbances and by simulations, and the observed
behavior verifies the simulations. The various options (…a, …b, and …c) represent varying degrees of calculation complexity,
wherein the most conservative criterion represents a very simple calculation, and the complexity increases as the criteria
becomes less conservative. No change made.
The drafting team contends that it is possible to provide phase fault backup protection while meeting the requirements of this
standard. The drafting team notes that the standard provides multiple options for setting transformer load-responsive phase

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relays to address this concern. If legacy approaches do not allow the entity to meet the requirement and protection objectives,
other approaches may be necessary. To prevent equipment damage from excessive time exposed to overload conditions, the
drafting team has included exclusions for dedicated generator and transformer overload protection that operates in time frames
appropriate to overload protection. No change made.
Texas Reliability
Entity

Texas RE generally supports this standard as written, other than the use of the term
*Regional Reliability Organization* in Table 1 as described above. Our other comments
are provided for consideration by the drafting team.

Response: The reference to “…or other entity as specified by the Regional Reliability Organization (RRO)” has been removed from
the standard. Change made.
Exelon and its
affiliates

The Constellation Energy Nuclear Generation (CENG) NERC Registered Affiliates
reiterate their concern in regards to the following comments. The Application
Guidelines state that the reliability objective of PRC-025 is to cover, “all loadresponsive protective relays that are affected by increased generator output in
response to system disturbances.” Section 3.2.3 of PRC-025-1 requires clarification
simply because the Unit Auxiliary Transformers (UAT’s) are not necessarily directly
connected to the generator, but there are indirect link to the generator operation. The
UAT’s are ok to be included to the applicability of this standard, but section 3.2.3 could
use more detailed explanation. Moreover, the webinar on 5/15/13 pointed out that a
decrease in HV system voltage would affect the plant MV voltage as well, causing a
proportional increase in current (at constant power draw by plant auxiliary loads) and
thereby potentially tripping UAT loadability relays. Reduction in frequency during
disturbances will strongly reduce the power drawn of pumps and fans, however, so MV
current may actually drop despite the HV voltage reduction being experienced. This
point of view is supported by the statement in the 12/13/2012 webinar that UAT relay
trips are not known to have caused the loss of any generation units during the
northeast blackout of ‘03, so extending PRC-025 applicability to UATs provides only a
hypothetical benefit that has not been observed (or has in fact been disproved) in

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practice.
CENG state that Facilities, UAT’s in Section 3.2.3 is appropriate to include it, but there
need to be a specific explanation as to the affect of MW due to grid disturbance affect
the generator output. An investigation and evaluation of the protection systems for
unit auxiliary transformers and the UAT’s lack of impact on generator loadability
should be considered.

Response: The Purpose statement was modified in the last draft to not be generator specific. The standard addresses generation
Facilities in general and the criteria provide reasonable loadability settings that are within the capability of the equipment the
standard is addressing. The purpose statement has been modified to clarify risk to associated equipment. Change made.
The drafting team contends that the load-responsive protection for any UAT that supplies “running station power” to the plant,
such that tripping of the UAT will cause the generator to trip, should be addressed by the draft standard. The drafting team has
revised the Table 1 criteria for UAT protection in the Standard and the Guidelines and Technical Basis discussion accordingly.
Change made.
Consumers Energy

Yes

Page 3 of 20, 3.2: Blackstart Resources that would not otherwise be defined as part of
the BES should not be included in the Facilities. Although voltage swings will occur
during restarting of the system, the detailed planning to control the electrical paths
and the placement of operating personnel to key substation locations preclude the
need for loadability criteria for these small generators. Blackstart Resources should be
removed from the list of Facilities.
Response: The drafting team contends that during Blackstart conditions the generator
may experience extreme voltage and loading swings; therefore, Blackstart units are
included and apply to the standard. If such generators are excluded from the
applicability of the standard, they may not perform as expected to facilitate system
restoration. Also, the drafting team notes that the standard only applies to those
Blackstart resources identified in the Transmission Operator’s system restoration plan
(i.e., SRP). No change made.

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Page 8 of 20, Exceptions: The Drafting Team has added one bullet item to and modified
one in the list of Exceptions. The first one recognizes the need to operate within
generator short time capabilities and is acceptable. The second exclusion attempts to
place an operator response time of 15 minutes or greater to a transformer overload
condition. While a system disturbance may continue for extended periods, we believe
that the 15 minute time frame far exceeds the practical relay operate time of standard
electromechanical, static or digital protective relays. The operate time characteristics
for most relays, as drawn on the manufacturers’ time-current curves, are much faster
than 15 minutes. Traditional relay curves are drawn to begin at 1.5 times pickup. The
maximum relay operate times at that defined relay pickup is typically in the 2-5 minute
range. Considering that the relay curves do not extend beyond a few minutes, a time
specification beyond 5 minutes is unrealistic. The wording of the last exception should
be changed to exclude: “Protection systems that detect transformer overloads and are
designed to respond in time periods which are greater than 2 minutes”
Response: The drafting team intends to exempt schemes that are explicitly designed
for overload protection, for which characteristics would be defined for the time period
in the bullet. Load-responsive relays that respond otherwise must meet the criteria in
Table 1. The proposed change to 2 minutes in the referenced exclusion may not be
sufficient to allow the system voltage to recover for the conditions being addressed by
this standard. No change made.
Page 14-15 of 20, 8a, 8b and 8c: The standard Pickup Setting Criteria for the step-up
transformer overcurrent element pickup is stated as 115% of any of three calculated
currents. In these cases the step-up transformer can probably withstand the high
currents for a short period of time, however all generators cannot be expected to
operate up to this percent current. It should be recognized that the control functions
set to protect the generator short time capabilities may supersede the operation of the
overcurrent element. Therefore any dynamic modeling of a generator must include
the excitation limitations. If the overcurrent element is set to operate to protect the
generator, then the pickup criteria must be changed to limits of the particular

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generator. A fourth alternative 8d should be created to recognize generator limits and
allow for setting the pickup and timing of the overcurrent element to protect the
generator.
Response: Proposed PRC-025-1 is based on system conditions where the generator is
expected to provide full field forcing until such a time as the excitation system controls
act to bring the generator back to within its steady state capability curve. Options 8a,
8b, and 8c establish that the GSU shall not trip for the identical conditions for which
the generator criteria are established. No change made.
Page 17 of 20, 13a and 13b: Unit auxiliary transformers are normally sized to carry all
of the station power loads for the expected range of the generator operating voltage.
A transformer high side overcurrent relay should be set to allow the transformer
loading, with margin. Since the standard is based upon “widely depressed” system
voltage and the standard recognizes that the generator will be supplying VARs to the
system, the generator terminal voltage will most likely be at or above rated. The
pickup criteria are unnecessarily complicated by the inclusion of 13b. We recommend
retaining 13a and the removal of 13b.
Response: The drafting team contends that the load-responsive protection for any UAT
that supplies “running station power” to the plant, such that tripping of the UAT will
cause the generator to trip, should be addressed by the draft standard. The drafting
team has revised the Table 1 criteria for UAT protection in the Standard and the
Guidelines and Technical Basis discussion accordingly. Change made.
The UAT can be connected at a variety of points; for system-connected UAT, the UAT
primary winding will see approximately 0.85 p.u. voltage; for unit-connected UAT, the
drafting team estimates that this voltage will be 0.9 to 0.95 p.u. voltage.
The drafting team has proposed a 150% margin for these relays rather than requiring
an analysis of the connected loads for depressed voltage; the margin includes
consideration for the increased current called for by these loads as well as normal relay

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setting tolerances. Some entities have indicated that 13b may be useful; therefore the
drafting team has decided to not remove it. No change made.

Response: The drafting team thanks you for your comments.

END OF REPORT

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Standard PRC-023-3 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for a 45-day informal comment period from January
25, 2013 to March 11, 2013 along with a red-lined Draft 1 of the revised standard.
3. Draft 2 of the revised standard was posted for a 30-day formal comment period from April 25,
2013 to May 24, 2013.

Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 3 of
PRC-023-3 – Transmission Relay Loadability for a 45-day formal comment period and initial
ballot.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

June 2013

10-day Recirculation Ballot

August 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version

Date

Action

Change
Tracking

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

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Standard PRC-023-3 — Transmission Relay Loadability

Version

Date

Action

Change
Tracking

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinator
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above, except lines that are
used exclusively to export energy directly from a Bulk Electric System
(BES) generating unit or generating plant to the network.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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 Requirement 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, except lines and
transformers that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network.
4.2.2.2 Transmission lines operated below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES, except

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Standard PRC-023-3 — Transmission Relay Loadability
lines and transformers that are used exclusively to export energy directly
from a BES generating unit or generating plant to the network.
Effective Dates: See Implementation Plan.
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 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, 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. Not used.
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.

1

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.

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Standard PRC-023-3 — 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 capability2.
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 temperature3.
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.

2

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
3

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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)
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

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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.

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Standard PRC-023-3 — Transmission Relay Loadability
The Planning Coordinator shall retain documentation of the most recent review process
required in Requirement 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 Requirement 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 Enforcement Authority 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.

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Standard PRC-023-3 — Transmission Relay Loadability

2.

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 BES 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.

R2

R3

N/A

N/A

N/A

N/A

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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

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 7, 8, 9,
12, or 13 did not use the calculated
circuit capability as the Facility
Rating of the circuit.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

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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.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

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High
months or more 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 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)

Severe
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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

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Standard PRC-023-3 — 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

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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. Not used.
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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 Bulk
Electric System.
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 Interconnection Reliability Operating Limit (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 analyses4 performed by the Planning Coordinator for the one-tofive-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.
4

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

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Standard PRC-023-3 — Transmission Relay Loadability
d. The threshold for selection of the circuit 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.

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.

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Standard PRC-023-3 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for a 45-day informalformal comment period fromon
January 25, 2013 to March 11, 2013 along with a red-lined Draft 1 of the revised
standard.
3. Draft 2 of the revised standard was posted for a 30-day formal comment period from April 25,
2013 to May 24, 2013.

Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 31 of
PRC-023-3 – Transmission Relay Loadability for a 4530-day formal comment period and initial
ballot.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

JuneAugust 2013

10-day Recirculation Ballot

AugustOctober 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version

Date

Action

Change
Tracking

1

February 12,
2008

Approved by Board of Trustees

New

1

March 19, 2008

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

Errata

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Standard PRC-023-3 — Transmission Relay Loadability

Version

Date

Action

Change
Tracking

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1,
4.2.3, or 4.2.4 (Circuits Subject to Requirements R1 – R5, R7, and R8).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1,
4.2.3, or 4.2.4 (Circuits Subject to Requirements R1 – R5, R7, and R8), provided
those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinator
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above, except lines that are
used exclusively to export energy directly from a Bulk Electric System
(BES) generating unit or generating plant to the network.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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 Requirement 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, except lines and
transformers that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network.
4.2.2.2 Transmission lines operated below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES, except

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Standard PRC-023-3 — Transmission Relay Loadability
lines and transformers that are used exclusively to export energy directly
from a BES generating unit or generating plant to the network.
4.2.3 Circuits Subject to Requirement R7
4.2.3.1 Transmission lines that are used solely to export energy directly from a
BES generating unit or generating plant to the network.
4.2.4 Circuits Subject to Requirement R8
4.2.4.1 Transformers with low voltage terminals connected below 200 kV,
including generator step-up transformers, that are used solely to export
energy directly from a BES generating unit or generating plant to the
network.
5. Effective Dates: See Implementation Plan.
.
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 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.

1

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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. Not used.
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
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 capability2.
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 temperature3.
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:

2

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

3

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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.
R7. Each Transmission Owner and Distribution Provider shall set their load responsive relays in
accordance with PRC-023-3, Attachment C at the terminals of the generator interconnection
Facility. [Violation Risk Factor: High] [Time Horizon: Long Term Planning].

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Standard PRC-023-3 — Transmission Relay Loadability
R8. Transmission Owner and Distribution Provider shall set their load responsive relays in
accordance with PRC-023-3, Attachment C at the terminals of the generator step-up transformer.
[Violation Risk Factor: High] [Time Horizon: Long Term Planning].
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 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 PRC-023-3, 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)
M7. Each Transmission Owner and Distribution Provider shall have evidence (e.g., summaries of
calculations, spreadsheets, simulation reports, or setting sheets) to show that each of its
generator interconnection Facility relays is set according to one of the criteria in Attachment C.
(R7)

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Standard PRC-023-3 — Transmission Relay Loadability
M8. Each Transmission Owner and Distribution Provider shall have evidence (e.g., summaries of
calculations, spreadsheets, simulation reports, or setting sheets) to show that each of its
generator step-up transformer relays is set according to one of the criteria in Attachment C.
(R8)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement AuthorityMonitoring Responsibility
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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, R7, and R8 for
three calendar years.
The Planning Coordinator shall retain documentation of the most recent review process
required in Requirement 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 Requirement 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 Enforcement Authority 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.

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Standard PRC-023-3 — Transmission Relay Loadability

2.

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 BESBulk
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.

R2

R3

N/A

N/A

N/A

N/A

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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

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 7, 8, 9,
12, or 13 did not use the calculated
circuit capability as the Facility
Rating of the circuit.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

Project 2010-13.2 Phase 2 Relay Loadability (Draft 3: June 102: April 24, 2013)

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.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

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High
months or more 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 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)

Severe
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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

(part 6.2)

Severe
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 the standard.

R7

R8

N/A

N/A

N/A

N/A

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N/A

The responsible entity did not set
one of its generator
interconnection Facility relays in
accordance with the criteria in
Attachment C.

N/A

The responsible entity did not set
one of its generator step-up
transformer relays in accordance
with the criteria in Attachment C.

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Standard PRC-023-3 — 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

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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. Not used.
2.4. Protective relays applied at the terminals of generation Facilities in accordance with NERC
Reliability Standard PRC-025-1 or its successor(s).
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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 Bulk
Electric SystemBES.
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 Interconnection Reliability Operating Limit (IROL),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 analyses4 performed by the Planning Coordinator for the one-tofive-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.
4

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

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Standard PRC-023-3 — Transmission Relay Loadability
d. The threshold for selection of the circuit 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.

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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — Attachment C
The following criteria shall be used to set load-responsive relays on generator interconnection Facilities and generator-step-up transformers.
This standard does not require the responsible entity to use any of the protective functions listed in Table 1. Each responsible entity that applies
load-responsive protective relays on Facilities listed in 4.2.3 and 4.2.4, Facilities shall use one of the following Options 1-12 in Table 1, Relay
Loadability Evaluation Criteria (“Table 1”), to set each load-responsive protective relay element according to its application and relay type. The
bus voltage is based on the criteria for the various applications listed in Table 1.
Relay pickup setting criteria values related to synchronous generators are derived from the unit’s maximum gross Real Power capability, in
megawatts (MW), as reported to the Transmission Planner or other entity as specified by the Regional Reliability Organization (RRO), and the
unit’s Reactive Power capability, in megavoltampere-reactive (Mvar), is determined by calculating the MW value based on the unit’s nameplate
megavoltampere (MVA) rating at rated power factor. If different seasonal capabilities are reported, the maximum capability shall be used for the
purposes of this standard.
Relay pickup setting criteria values related to asynchronous generators (including inverter-based installations) are derived from the site’s aggregate
maximum complex power capability, in MVA, as reported to the Transmission Planner or other entity as specified by the Regional Reliability
Organization (RRO), including the Mvar output of any static or dynamic reactive power devices.
For the application case where synchronous and asynchronous generator types are combined on a generator step-up transformer or on a generator
interconnection Facility, the pickup setting criteria shall be determined by vector summing the pickup setting criteria of each generator type, and
using the bus voltage for the given synchronous generator application and relay type.
Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers
with deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest
generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU
turns ratio shall be used.
Any relay elements that are in service only during start up, when the generator is disconnected, or when other Protection System components fail
are excluded. Examples of exclusions include, but are not limited to, the following:
Load-responsive protective relay elements that are armed only when the generator is disconnected from the system, (e.g., non-directional
overcurrent elements used in conjunction with inadvertent energization schemes, and open breaker flashover schemes),
Phase fault detector relay elements employed to supervise other load-responsive phase distance elements (in order to prevent false
operation in the event of a blown secondary fuse) provided the distance element is set in accordance with the criteria outlined in the
standard,
Table 1
The Table is structured and formatted to aid the reader with identifying an option for a given load-responsive protective relay.
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Standard PRC-023-3 — Transmission Relay Loadability
The first column identifies the application (e.g., generator step-up transformers and generator interconnection Facilities). Dark blue horizontal
bars, excluding the header which repeats at the top of each page, demarcate the various applications.
The second column identifies the load-responsive protective relay (e.g., 21, 51, or 67) according to the applied application in the first column. A
light blue horizontal bar between the relay types is the demarcation between relay types for a given application. These light blue bars will contain
no text.
The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting load-responsive
protective relays according to the application and applied relay type. Another, shorter, light blue bar contains the word “OR,” and reveals to the
reader that the relay for that application has one or more options (i.e., “ways”) to determine the bus voltage and pickup setting criteria in the fourth
and fifth column, respectively. The bus voltage column and pickup setting criteria columns provide the criteria for determining an appropriate
setting.
The table is further formatted by alternately shading groups of relays within a similar application. Also, intentional buffers were added to the table
such that similar options would be paired together on a per page basis. Note that some applications may have additional pairing that might occur
on adjacent pages.

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

1a

Generator stepup transformer
connected to
synchronous
generators

Phase distance
relay (21) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 7

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

1b

OR

1c

The same application continues on the next page with a different relay type

5

Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with
deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When
the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU turns ratio shall be used.

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

2a

Generator stepup transformer
connected to
synchronous
generators

Phase time
overcurrent relay
(51) – installed on
generator-side of
GSU
If the relay is
installed on the
high-side of GSU
use Option 8

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

2b

OR

2c

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

3a

Generator stepup transformer
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system– installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 9

Bus Voltage5

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the transformer
turns ratio and impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 150% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

3b

OR

3c

A different application starts on the next page

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Generator stepup transformer
connected to
asynchronous
generators only
(including
inverter-based
installations)

Relay Type
Phase distance
relay (21) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 10

Phase time
overcurrent relay
(51) – installed on
generator-side of
GSU
If the relay is
installed on the
high-side of GSU
use Option 11

Option

Bus Voltage5

Pickup Setting Criteria

4

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated impedance
derived from 130% of the maximum aggregate nameplate MVA
output at rated power factor (including the Mvar output of any static or
dynamic reactive power devices)

5

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer
for overcurrent relays installed on the
low-side

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system – installed
on generator-side
of GSU
If the relay is
installed on the
high-side of GSU
use Option 12

6

Bus Voltage5

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Pickup Setting Criteria

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

A different application begins below

7a

Generator
interconnection
Facilities
connected to
synchronous
generators

Phase distance
relay (21) –
directional toward
the Transmission
system

0.85 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The impedance element shall be set less than the calculated impedance
derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

7b

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

8a

Phase time
overcurrent relay
(51)

Generator
interconnection
Facilities
connected to
synchronous
generators

Bus Voltage5

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

8b

The same application continues on the next page with a different relay type

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type

Option

9a
Generator
interconnection
Facilities
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system

Bus Voltage5

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output – 120% of the aggregate generation MW
value, derived from the nameplate MVA rating at rated power factor

Simulated line voltage coincident with
the highest Reactive Power output
achieved during field-forcing in
response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer prior
to field-forcing

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross MW
reported to the Transmission Planner or other entity as specified by the
Regional Reliability Organization (RRO), and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined by
simulation

OR

9b

A different application starts on the next page

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Standard PRC-023-3 — Transmission Relay Loadability

Table 1: Relay Loadability Evaluation Criteria
Application

Relay Type
Phase distance
relay (21) –
directional toward
the Transmission
system

Generator
interconnection
Facilities
connected to
asynchronous
generators only
(including
inverter-based
installations)

Phase time
overcurrent relay
(51)

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system

Option

Bus Voltage5

Pickup Setting Criteria

10

1.0 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated impedance
derived from 130% of the maximum aggregate nameplate MVA
output at rated power factor (including the Mvar output of any static or
dynamic reactive power devices)

11

1.0 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

12

1.0 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate nameplate
MVA output at rated power factor (including the Mvar output of any
static or dynamic reactive power devices)

End of Table 1

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Implementation Plan

PRC-023-3 – Transmission Relay Loadability

Project 2010-13.2 Phase II Relay Loadability
Requested Approvals

PRC-023-3 – Transmission Relay Loadability
Requested Retirements

PRC-023-2 – Transmission Relay Loadability
Prerequisite Approvals

PRC-025-1 – Generator Relay Loadability*
*A supplemental SAR was approved by the Standards Committee at their January 16-17, 2013 meeting to
authorize the drafting team to make changes to PRC-023-2 to comport with the proposed draft PRC-0251 – Generator Relay Loadability in order to establish a bright line between the applicability of loadresponsive protective relays in the current transmission and the proposed generator relay loadability
standards.
Revisions to Defined Terms in the NERC Glossary

None
Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is
no bright line to clearly distinguish which load-responsive protective relays pertain to the existing PRC-023-2 –
Transmission Relay Loadability standard, effective in the United States on July 1, 2012, and the proposed PRC025-1 – Generator Relay Loadability standard. To resolve this concern, the drafting team proposed to modify
the applicability section of PRC-023-2. The standard drafting team clarified, for each functional entity, the
applicability of PRC-023-2 by tying applicability to the terminal the load-responsive protective relay that it is
connected to within the Transmission system.

General Considerations

It is expected that the implementation period for PRC-023-2 will have been achieved, in part, by the time PRC023-3 is adopted by the NERC Board of Trustees and by the time of other approvals by applicable

governmental authorities. The proposed PRC-023-3 Implementation Plan now reflects specific milestone dates
that are known time periods consistent with PRC-023-2.
Applicable Entities

Distribution Provider
Generator Owner
Planning Coordinator
Transmission Owner
Effective Date
New Standard

PRC-023-3

First day of the first calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the
first day of the first calendar quarter beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.

Standards for Retirement

PRC-023-2

Midnight of the day immediately prior to the Effective Date of PRC-023-3 –
Transmission Relay Loadability in the particular jurisdiction in which the new
standard is becoming effective, except Requirement R1, Criterion 6 which will
remain in force until the effective date of PRC-025-1.

Implementation Plan for Definitions

No definitions are proposed as a part of this standard.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 2013)

2

Implementation Plan for PRC-023-3, Requirements R1 through R6

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to
this standard shall be 100% compliant on the following dates:
Implementation 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.

R1

For supervisory elements as
described in PRC-023-3 - Attachment
A, Section 1.6

For switch-on-to-fault schemes as
described in PRC-023-3 - Attachment
A, Section 1.3

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 2013)

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, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

The later of July 1,
2014 or first day of the
first calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

3

Implementation Date
Requirement

R1
(continued)

R2 and R3

Applicability

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

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

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 2013)

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

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 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

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 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

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

4

Implementation Date
Requirement

R2 and R3
continued

R4

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 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

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 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 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 Board of
First day of the first
Trustees adoption, or
calendar quarter six
as otherwise made
months after applicable effective pursuant to
regulatory approvals
the laws applicable to
such ERO
governmental
authorities

Applicability

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 2013)

5

Implementation Date
Requirement

R5

R6

Applicability

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

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 Owner,
and Distribution Providers must comply
with Requirements R1 through R5

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 2013)

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Later of January 1,
2014 or the first day of
the first calendar
quarter after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

6

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is
implemented. If the drafting team is recommending revisions, those changes are identified by the “Proposed Replacement” column.
Already Approved Standard
PRC-023-2
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

Proposed Replacement
PRC-023-3
4.1.Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection
systems as described in PRC-023-2 3 - Attachment A, applied at the
terminals of the 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-023-3 - Attachment A, applied at the
terminals of the 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 3 - Attachment A, applied at the
terminals of the 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

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1, Functional Entity creates a bright line between those load-responsive
protective relays that are applicable to PRC-023-3 – Transmission Relay Loadability and the proposed PRC-025-1 – Generator Relay Loadability.
This is evident by the minor changes to the Applicability text to distinguish the applicability of the relays by which “terminal” the load-responsive
protective relay is connected to within the Transmission system. Applicability is established by ownership of the load-responsive protective
relays, not the Facilities.

Implementation Plan (PRC-023-3)
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7

Already Approved Standard

Proposed Replacement

PRC-023-2
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 below 100 kV and

PRC-023-3
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and
above, except lines that are used exclusively to
export energy directly from a BES generating unit
or generating plant to the network.
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

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Already Approved Standard
transformers with low voltage terminals connected
below 100 kV that are part of the BES

Proposed Replacement
connected at 100 kV to 200 kV, except lines and
transformers that are used exclusively to export
energy directly from a BES generating unit or
generating plant to the network.
4.2.2.2 Transmission lines operated below 100 kV and
transformers with low voltage terminals
connected below 100 kV that are part of the BES,
except lines and transformers that are used
exclusively to export energy directly from a BES
generating unit or generating plant to the
network.

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1 Facilities, creates a bright line between those Facilities that are applicable
to PRC-023-3 – Transmission Relay Loadability and those Facilities in the proposed PRC-025-1 – Generator Relay Loadability. The above
applicability items for Section 4.2 “Circuits” that are subject to the standard were modified to exclude those lines and transformers that are used
exclusively to export energy directly from a BES generating unit or generating plant to the network. The added text reads: “except lines and
transformers that are used exclusively to export energy directly from a BES generating unit or generating plant to the network” and is found in
Sections 4.2.1.1, 4.2.2.1, and 4.2.2.2. This eliminates an overlap with the proposed changes in PRC-025-1 and places the performance for lines
and transformers that are used exclusively to export energy directly from a BES generating unit or generating plant to the network under the
proposed PRC-025-1.

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Already Approved Standard
PRC-023-2 (Retirement)
R1, Criterion 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.”

Proposed Replacement
PRC-025-1 (New)
New Requirement
R1. Each Generator Owner, Transmission Owner, and Distribution
Provider shall apply settings that are in accordance with PRC-025-1 –
Attachment 1: Relay Settings, on each load-responsive protective relay
while maintaining reliable fault protection. [Violation Risk Factor: High]
[Time Horizon: Long-Term Planning]
*Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation
Criteria, Options 14 through 19. (See standard for details)

Notes: The Transmission Owner and Distribution Provider were added to the Applicability of the proposed PRC-025-1 and excluded lines that are
used exclusively to export energy directly from a Bulk Electric System (BES) generating unit or generating plant to the network; therefore,
Requirement R1, Criterion 6 has been removed from the proposed standard PRC-023-3 because this criterion is now replaced (i.e., superseded)
by the proposed PRC-025-1 – Generator Relay Loadability standard, Requirement R1 and its Attachment 1: Attachment 1: Relay Settings, Table 1:
Relay Loadability Evaluation Criteria, Options 14 through 19. Applicability concerning generation Facilities is now addressed in the proposed PRC025-1. Although, Requirement R1, Criterion 6 is not shown in the proposed PRC-023-3, it remains auditable while each entity assures its
compliance with the proposed PRC-025-1 criteria according to the provided Implementation Plan(s).
PRC-023-2 (Retirement)
R1, Attachment A, exclusion 2.4. “Generator protection relays that are
susceptible to load.”

None.

Notes: This exclusion has been superseded by the proposed PRC-025-1 standard that pertains to these relays. The proposed PRC-023-3 standard
does not include any criteria that are relevant to generator protection relays. The proposed PRC-025-1 standard establishes specific criteria for
generator load-responsive protective relays, and renders this exclusion unnecessary.

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Implementation Plan

PRC-023-3 – Transmission Relay Loadability

Project 2010-13.2 Phase II Relay Loadability
Requested Approvals

PRC-023-3 – Transmission Relay Loadability
Requested Retirements

PRC-023-2 – Transmission Relay Loadability
Prerequisite Approvals

PRC-025-1 – Generator Relay Loadability*
*A supplemental SAR was approved by the Standards Committee at their January 16-17, 2013 meeting to
authorize the drafting team to make changes to PRC-023-2 to comport with the proposed draft PRC-0251 – Generator Relay Loadability in order to establish a bright line between the applicability of loadresponsive protective relays in the current transmission and the proposed generator relay loadability
standards.
Revisions to Defined Terms in the NERC Glossary

None
Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is
no bright line to clearly distinguish which load-responsive protective relays pertain to the existing PRC-023-2 –
Transmission Relay Loadability standard, effective in the United States on July 1, 2012, and the proposed PRC025-1 – Generator Relay Loadability standard. To resolve this concern, the drafting team proposed to modify
the applicability section of PRC-023-2. The standard drafting team clarified, for each functional entity, the
applicability of PRC-023-2 by tying applicability to the terminal the load-responsive protective relay that it is
connected to within the Transmission system.
Requirements R1 though R6 continue to apply to the Generator Owner to avoid a potential gap in situations
where this entity owns load-responsive protective relays subject to transmission line relay loadability (PRC023). These situations could be the result of a current configuration or future changes or additions in
transmission configurations.

The proposed PRC-023-3 standard also includes two new Requirements, R7 and R8 to address load-responsive
protective relay loadability in cases where the Distribution Provider or Transmission Owner owns generator
interconnection Facilities or generator step-up (GSU) transformers. The implementation time for
Requirements R7 and R8 comports with the periods established in the proposed PRC-025-1 Implementation
Plan.
General Considerations

It is expected that the implementation period for PRC-023-2 will have been achieved, in part, by the time PRC023-3 is adopted by the NERC Board of Trustees and by the time of other approvals by applicable
governmental authorities. The proposed PRC-023-3 Implementation Plan now reflects specific milestone dates
that are known, time periods consistent with PRC-023-2, and an implementation period for new Requirements
R7 and R8.
Applicable Entities

Distribution Provider
Generator Owner
Planning Coordinator
Transmission Owner
Effective Date
New Standard

PRC-023-3

First day of the first calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the
first day of the first calendar quarter beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.

Standards for Retirement

PRC-023-2

Midnight of the day immediately prior to the Effective Date of PRC-023-3 –
Transmission Relay Loadability in the particular jurisdiction in which the new
standard is becoming effective, except Requirement R1, Criterion 6 which will
remain in force until the effective date of PRC-025-1..

Implementation Plan for Definitions

No definitions are proposed as a part of this standard.

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Implementation Plan for PRC-023-3, Requirements R1 through R6

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to
this standard shall be 100% compliant on the following dates:
Implementation 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.

R1

For supervisory elements as
described in PRC-023-3 - Attachment
A, Section 1.6

For switch-on-to-fault schemes as
described in PRC-023-3 - 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, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

The later of July 1,
2014 or first day of the
first calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

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Implementation Date
Requirement

R1
(continued)

R2 and R3

Applicability

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

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

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

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 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

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 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

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

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Implementation Date
Requirement

R2 and R3
continued

R4

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 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

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 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 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 Board of
First day of the first
Trustees adoption, or
calendar quarter six
as otherwise made
months after applicable effective pursuant to
regulatory approvals
the laws applicable to
such ERO
governmental
authorities

Applicability

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Implementation Date
Requirement

R5

R6

Applicability

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

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 Owner,
and Distribution Providers must comply
with Requirements R1 through R5

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Later of January 1,
2014 or the first day of
the first calendar
quarter after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

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Implementation Plan for PRC-023-3, Requirements R7 and R8

Load-responsive protective relays subject to the standard
Each Transmission Owner and Distribution Provider that owns load-responsive protective relays applicable to
this standard shall be 100% compliant on the following dates:
Implementation Date
Requirement

R7

Applicability

Each Transmission Owner
and Distribution Provider
shall set their load
responsive relays in
accordance with PRC-0233, Attachment C at the
terminals of the generator
interconnection Facility.

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months after applicable
regulatory approvals

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months after Board of Trustees
adoption, or as otherwise
made effective pursuant to the
laws applicable to such ERO
governmental authorities

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months after applicable
regulatory approvals

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months after Board of Trustees
adoption, or as otherwise
made effective pursuant to the
laws applicable to such ERO
governmental authorities

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Implementation Date
Requirement

R8

Applicability

Transmission Owner and
Distribution Provider shall
set their load responsive
relays in accordance with
PRC-023-3, Attachment C
at the terminals of the
generator step-up
transformer.

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months after applicable
regulatory approvals

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months after Board of Trustees
adoption, or as otherwise
made effective pursuant to the
laws applicable to such ERO
governmental authorities

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months after applicable
regulatory approvals

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months after Board of Trustees
adoption, or as otherwise
made effective pursuant to the
laws applicable to such ERO
governmental authorities

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Load-responsive protective relays which become applicable to the standard
Each Transmission Owner and Distribution Provider that owns load-responsive protective relays that become
applicable to this standard, not because of the actions of the Transmission Owner and Distribution Provider
including, but not limited to changes in NERC Registration Criteria, Bulk Electric System (BES) definition, or any
other non-Generator Owner action, shall be 100% compliant on the following dates:
Implementation Date
Requirement

R7

Applicability

Each Transmission Owner
and Distribution Provider
shall set their load
responsive relays in
accordance with PRC-0233, Attachment C at the
terminals of the generator
interconnection Facility.

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months beyond the date the
load-responsive protective
relays become applicable to
the standard

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months beyond the date the
load-responsive protective
relays become applicable to
the standard

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months beyond the date the
load-responsive protective
relays become applicable to
the standard

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months beyond the date the
load-responsive protective
relays become applicable to
the standard

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Implementation Date
Requirement

R8

Applicability

Transmission Owner and
Distribution Provider shall
set their load responsive
relays in accordance with
PRC-023-3, Attachment C
at the terminals of the
generator step-up
transformer.

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months beyond the date the
load-responsive protective
relays become applicable to
the standard

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is not
necessary, the first day 48
months beyond the date the
load-responsive protective
relays become applicable to
the standard

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months beyond the date the
load-responsive protective
relays become applicable to
the standard

Where determined by the
Transmission Owner and
Distribution Provider that
replacement or removal is
necessary, the first day 72
months beyond the date the
load-responsive protective
relays become applicable to
the standard

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Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is
implemented. If the drafting team is recommending revisions, those changes are identified by the “Proposed Replacement” columnin bold
blue with underlining for additions and for deletions in bold red with a strikeout.
Already Approved Standard
PRC-023-2
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

Proposed Replacement
PRC-023-3
4.1.Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection
systems as described in PRC-023-2 3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1, 4.2.3, or 4.2.4 (Circuits Subject
to Requirements R1 – R5, R7, and R8).
4.1.2 Generator Owners with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the 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 3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1, 4.2.3, or 4.2.4 (Circuits Subject
to Requirements R1 – R5, R7, and R8), provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinators

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1, Functional Entity creates a bright line between those load-responsive
protective relays that are applicable to PRC-023-3 – Transmission Relay Loadability and the proposed PRC-025-1 – Generator Relay Loadability.
This is evident by the minor changes to the Applicability text to distinguish the applicability of the relays by which “terminal” the load-responsive
protective relay is connected to within the Transmission system. Applicability is established by ownership of the load-responsive protective

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Already Approved Standard

Proposed Replacement

relays, not the Facilities.

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Already Approved Standard

Proposed Replacement

PRC-023-2
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 below 100 kV and

PRC-023-3
New applicability
4.2
Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and
above, except lines that are used exclusively to
export energy directly from a Bulk Electric
System (BES) generating unit or generating plant
to the network.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV
selected by the Planning Coordinator in
accordance with Requirement 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 Requirement 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
Requirement 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 Requirement R6.

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Already Approved Standard
transformers with low voltage terminals connected
below 100 kV that are part of the BES
None.

Proposed Replacement
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, except lines that
are used exclusively to export energy directly
from a Bulk Electric System (BES) generating unit
or generating plant to the network.
4.2.2.2 Transmission lines operated below 100 kV and
transformers with low voltage terminals
connected below 100 kV that are part of the BES,
except lines that are used exclusively to export
energy directly from a Bulk Electric System (BES)
generating unit or generating plant to the
network.
4.2.3 Circuits Subject to Requirement R7
4.2.3.1 Transmission lines that are used solely to export
energy directly from a BES generating unit or
generating plant to the network.
4.2.4 Circuits Subject to Requirement R8
4.2.2.2 Transformers with low voltage terminals
connected below 200 kV, including generator
step-up transformers, that are used solely to
export energy directly from a BES generating unit
or generating plant to the network.

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1 Facilities, creates a bright line between those Facilities that are applicable

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 102: April 24, 2013)

14

Already Approved Standard

Proposed Replacement

to PRC-023-3 – Transmission Relay Loadability and those Facilities in the proposed PRC-025-1 – Generator Relay Loadability. The above
applicability items for Section 4.2 “Circuits” that are subject to the standard were modified to exclude those lines and transformers that are used
exclusively to export energy directly from a BES generating unit or generating plant to the network. The added text reads: “except lines and
transformers that are used exclusively to export energy directly from a BES generating unit or generating plant to the network” and is found in
Sections 4.2.1.1, 4.2.2.1, and 4.2.2.2. This eliminates an overlap with the proposed changes in PRC-025-1 and places the performance for lines
and transformers that are used exclusively to export energy directly from a BES generating unit or generating plant to the network under the
proposed PRC-025-1.Notes: The above two new applicability items for circuits subject to the standard were added to address to situations where
the Distribution Provider or Transmission Owner own either generator interconnection Facilities or generator step-up (GSU) transformers,
respectively.
PRC-023-2 (Retirement)
R1, Criterion 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.”.

PRC-025-1 (New)023-3
New Requirement
R1.
Each Generator Owner, Transmission Owner, and Distribution
Provider shall apply settings that are in accordance with PRC025-1 – Attachment 1: Relay Settings, on each load-responsive
protective relay while maintaining reliable fault protection.
[Violation Risk Factor: High] [Time Horizon: Long-Term
Planning]
R7.
Each Transmission Owner and Distribution Provider shall set
their load responsive relays in accordance with PRC-023-3, Attachment
C at the terminals of the generator interconnection Facility. [Violation
Risk Factor: High] [Time Horizon: Long Term Planning].

Notes: The Transmission Owner and Distribution Provider were added to the Applicability of the proposed PRC-025-1 and excluded lines that are
used exclusively to export energy directly from a Bulk Electric System (BES) generating unit or generating plant to the network; therefore,
Requirement R1, Criterion 6 has been removed from the proposed standard PRC-023-3 because this criterion is now replaced (i.e., superseded)
by the proposed PRC-025-1 – Generator Relay Loadability standard, Requirement R1 and its Attachment 1: Attachment 1: Relay Settings, Table 1:
Relay Loadability Evaluation Criteria, Options 14 through 19. Applicability concerning generation Facilities is now addressed in the proposed PRCImplementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 102: April 24, 2013)

15

Already Approved Standard

Proposed Replacement

025-1. Although, Requirement R1, Criterion 6 is not shown in the proposed PRC-023-3, it remains auditable while each entity assures its
compliance with the proposed PRC-025-1 criteria according to the provided Implementation Plan(s).Notes: This new requirement is included to
address a gap concerning generator step-up (GSU) transformers where the Transmission Owner or Distribution Provider has applied loadresponsive protective relays. Referencing the proposed Applicability section 4.2.4, Circuits Subject to Requirement R8, this requirement closes
the gap for those transformers that have low voltage terminals connected below 200 kV. Currently, only those Transmission system transformers
with low voltage terminals connected at 200 kV and above are applicable to the Transmission Owner or Distribution Provider or transformers
with low voltage terminals under 200 kV if the Planning Coordinator determines (in accordance with requirement R6) that they should be subject
to PRC-023-3. This is identified by in the proposed Applicability 4.2.1.4. This requirement eliminates the gap between the proposed PRC-023-3
and PRC-025-1 so that generator step-up (GSU) transformers (i.e., where the Transmission system transformer is the transmission line
termination – Criterion 10) apply to the Transmission Owner or Distribution Provider in the proposed PRC-023-3 in the same manner as the
Generator Owner in the proposed PRC-025-1.
Circuits subject to R8 are primarily GSU transformers and also include “aggregated generator transformers” – those connecting wind farms, and
photovoltaic sites.
PRC-023-2 (Retirement)
R1, Attachment A, exclusion 2.4. “Generator protection relays that are
susceptible to load.”None.

None.
PRC-023-3
New Requirement
R8.
Transmission Owner and Distribution Provider shall set their
load responsive relays in accordance with PRC-023-3, Attachment C at
the terminals of the generator step-up transformer. [Violation Risk
Factor: High] [Time Horizon: Long Term Planning].

Notes: This exclusion has been superseded by the proposed PRC-025-1 standard that pertains to these relays. The proposed PRC-023-3 standard
does not include any criteria that are relevant to generator protection relays. The proposed PRC-025-1 standard establishes specific criteria for
generator load-responsive protective relays, and renders this exclusion unnecessary.Notes: The above new Requirement R7 addresses a gap
between the proposed PRC-023-3 and PRC-025-1 standards. This requirement applies to the condition where the Transmission Owner or

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 102: April 24, 2013)

16

Already Approved Standard

Proposed Replacement

Distribution Provider apply load-responsive protective relays on a generator interconnection Facility(ies). Rather than add Transmission Owner
and Distribution Provider to the proposed PRC-025-1, it was equally and efficient to include the same loadability criteria as the proposed PRC025-1 in the proposed PRC-023-3 standard. Requirement R7 proposes to replace the current PRC-023-2, Requirement R1, Criterion 6 with a new
requirement. Criterion 6 for setting the load-responsive protective relays so they do not operate at or below 230% now has additional flexibility
in setting such relays according to Attachment C which is referenced in this new Requirement, R7. The 230% criterion comports with the
loadability criteria found in the proposed PRC-023-3 Attachment C. The Transmission Owner and Distribution Provider in the proposed PRC-023-3
will have the same options for setting its load-responsive protective relays when applied on generator interconnection Facility(ies) as the
Generator Owner in the proposed PRC-025-1.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 102: April 24, 2013)

17

Unofficial Comment Form

Project 2010-13.2 Phase II Relay Loadability
PRC-023-3
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by August 5, 2013. If
you have questions please contact Scott Barfield-McGinnis at [email protected] or by
telephone at (404) 446-9689.
http://www.nerc.com/pa/Stand/Pages/Project-2010-13-2-Phase-2-Relay-Loadability-Generation.aspx
Summary of changes

The generator relay loadability standard drafting team (“SDT”) has revised the proposed the draft of
PRC-023-3 – Transmission Relay Loadability based on stakeholder comments received during its first
30-day formal posting. The following narrative is a summary of the significant improvements made to
the standard.
PRC-023-3

The SDT, based on industry stakeholder comments, made substantive changes to the PRC-023-3
standard. The chief change was removing the previously proposed Requirement R7 and R8 which
applied to the generator interconnection Facility and generator step-up transformer applicable to the
Distribution Provider and Transmission Owner. With this change the SDT added the Distribution
Provider and Transmission Owner to the applicability of PRC-025-1 and removed the applicability of
those lines and transformers that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network from PRC-023 to establish the bright line between
standards according to stakeholder comments.
•

•

Applicability
o Removed references to Requirements R7 and R8
o Added the exception to sections 4.2.1.1, 4.2.2.1, and 4.2.2.2 to exclude lines and
transformers that are used exclusively to export energy directly from a BES generating unit
or generating plant to the network
o Removed the sections 4.2.3 and 4.2.4
Requirements
o Requirement R1, criterion 6 was removed to comport with the elimination of addressing
load-responsive protective relays on lines and transformers that are used exclusively to
export energy directly from a BES generating unit or generating plant to the network

•
•
•
•
•

Measures
o Removed the proposed Requirement R7
o Removed the proposed Requirement R8
Compliance
o Removed R7 and R8 references
Violation Severity Levels
o Removed R7 and R8
Attachment A
o Revised criterion 2.4 as “Note Used” since it is no longer needed
Attachment C
o Removed due to Requirements R7 and R8 being eliminated

Implementation Plan

•

Updated to reflect the transition of PRC-023-3 Requirement R1, Criterion 6 to the proposed
PRC-025-1 criterion

VRF/VSL Justifications

•

No change, not being provided for comment because the SDT is making substantive changes.
Only references to Requirement R1, criterion 6 were removed

Unofficial Comment Form
Project 2010-13.2–Phase II Relay Loadability (Draft 3: PRC-023-3)

2

*Please use the electronic comment form to submit your final comments to NERC.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Please note that the official comment form does not retain formatting (even if it appears to transfer
formatting when you copy from the unofficial Word version of the form into the official electronic
comment form). If you enter extra carriage returns, bullets, automated numbering, symbols, bolding,
italics, or any other formatting, that formatting will not be retained when you submit your
comments.
•
•
•
•
•

Separate discrete comments by idea, e.g., preface with (1), (2), etc.
Use brackets [] to call attention to suggested inserted or deleted text.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
Do not use formatting such as extra carriage returns, bullets, automated numbering, bolding, or
italics.
Please do not repeat other entity’s comments. Select the appropriate item to support another
entity’s comments. An opportunity to enter additional or exception comments will be available.

1. The drafting team has modified the Applicability in PRC-023-3 to establish a bright line between
PRC-023-3 and PRC-025-1 by excluding lines that are used exclusively to export energy directly
from a BES generating unit or generating plant to the network and GSU and in doing so included
the DP and TO in PRC-025-1. Do you agree that this establishes a bright line for the owners of
load-responsive protective relays applied these Facilities (i.e., except lines that are used
exclusively to export energy directly from a BES generating unit or generating plant to the
network and GSUs)? If not, provide specific detail that would improve the PRC-023-3
Applicability clarity or any other comment.
Yes
No
Comments:

Unofficial Comment Form
Project 2010-13.2–Phase II Relay Loadability (Draft 3: PRC-023-3)

3

Standards Announcement
Project 2010-13.2 Phase 2 of Relay Loadability: Generation
PRC-023-3 and PRC-025-1
45-Day Formal Comment Period for PRC-023-3: June 20, 2013 – August 5, 2013
Ballot Pools Forming Now: June 20, 2013 - July 19, 2013
Upcoming Initial Ballot: July 26, 2013 - August 5, 2013
30-Day Formal Comment Period for PRC-025-1: June 20, 2013 – July 19, 2013
Upcoming Successive Ballot and Non-Binding Poll: July 10, 2013 – July 19, 2013
Now Available

A 45-day formal comment period for PRC-023-3 – Transmission Relay Loadability is now being
conducted through 8 p.m. Eastern on Monday, August 5, 2013. A ballot pool is being formed and the
ballot pool window is open through 8 a.m. Eastern on Friday, July 19, 2013 (please note that ballot
pools close at 8 a.m. Eastern and mark your calendar accordingly).
A 30-day formal comment period for PRC-025-1 – Generator Relay Loadability is now being conducted
through 8 p.m. Eastern on Friday, July 19, 2013.
Background information for this project can be found on the project page.
Instructions for Joining Ballot Pools
A ballot pool is being formed for the standard PRC-023-3. Registered Ballot Body members must
join the ballot pool to be eligible to vote in the balloting of PRC-023-3. Registered Ballot Body
members may join the ballot pools at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using the “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list server.) The ballot pool list server for this ballot pool is:
Initial Ballot: [email protected]
The ballot pool is open through 8 a.m. Eastern on Friday, July 19, 2013.

Instructions for Commenting
To submit comments, please use this electronic form for PRC-023-3 and this electronic form for
PRC-025-1. If you experience any difficulties in using the electronic form, please contact Wendy
Muller . An off-line, unofficial copy of the comment forms are posted on the project page.
Next Steps

An initial ballot of PRC-023-3 and a successive ballot of PRC-025-1 and non-binding poll (for PRC025-1 only) of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for
both standards will be conducted as previously outlined.
Standards Development 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement:
Project 2010-13.2 Phase 2 of Relay Loadability: Generation

2

Standards Announcement
Project 2010-13.2 Phase 2 of Relay Loadability: Generation
PRC-023-3 and PRC-025-1
45-Day Formal Comment Period for PRC-023-3: June 20, 2013 – August 5, 2013
Ballot Pools Forming Now: June 20, 2013 - July 19, 2013
Upcoming Initial Ballot: July 26, 2013 - August 5, 2013
30-Day Formal Comment Period for PRC-025-1: June 20, 2013 – July 19, 2013
Upcoming Successive Ballot and Non-Binding Poll: July 10, 2013 – July 19, 2013
Now Available

A 45-day formal comment period for PRC-023-3 – Transmission Relay Loadability is now being
conducted through 8 p.m. Eastern on Monday, August 5, 2013. A ballot pool is being formed and the
ballot pool window is open through 8 a.m. Eastern on Friday, July 19, 2013 (please note that ballot
pools close at 8 a.m. Eastern and mark your calendar accordingly).
A 30-day formal comment period for PRC-025-1 – Generator Relay Loadability is now being conducted
through 8 p.m. Eastern on Friday, July 19, 2013.
Background information for this project can be found on the project page.
Instructions for Joining Ballot Pools
A ballot pool is being formed for the standard PRC-023-3. Registered Ballot Body members must
join the ballot pool to be eligible to vote in the balloting of PRC-023-3. Registered Ballot Body
members may join the ballot pools at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using the “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list server.) The ballot pool list server for this ballot pool is:
Initial Ballot: [email protected]
The ballot pool is open through 8 a.m. Eastern on Friday, July 19, 2013.

Instructions for Commenting
To submit comments, please use this electronic form for PRC-023-3 and this electronic form for
PRC-025-1. If you experience any difficulties in using the electronic form, please contact Wendy
Muller . An off-line, unofficial copy of the comment forms are posted on the project page.
Next Steps

An initial ballot of PRC-023-3 and a successive ballot of PRC-025-1 and non-binding poll (for PRC025-1 only) of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for
both standards will be conducted as previously outlined.
Standards Development 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement:
Project 2010-13.2 Phase 2 of Relay Loadability: Generation

2

Standards Announcement

Project 2010-13.2 Phase 2 of Relay Loadability: Generation
PRC-023-3
Initial Ballot Results
Now Available

An initial ballot for PRC-023-3 – Transmission Relay Loadability concluded at 8 p.m. Eastern on
Thursday, August 8, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results
for the initial ballot.
Approval
Quorum: 80.05 %
Approval: 93.00 %
Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
Standards Development 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards

Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2010 -13.2 PRC-023 Ballot_1

Password

Ballot Period: 7/26/2013 - 8/8/2013
Ballot Type: Initial

Log in

Total # Votes: 313

Register

Total Ballot Pool: 391
Quorum: 80.05 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
93.00 %
Vote:
Ballot Results: The Standard has Passed

 Home Page
Summary of Ballot Results

Affirmative

Negative

Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote

1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals

1
2
3
4
5
6
7
8
9

108

1

67

0.931

5

0.069

0

7

29

9

0.5

5

0.5

0

0

0

1

3

86

1

62

0.939

4

0.061

0

4

16

29

1

18

0.9

2

0.1

0

4

5

90

1

62

0.873

9

0.127

0

8

11

54

1

37

0.881

5

0.119

0

0

12

1

0

0

0

0

0

0

0

1

4

0.3

3

0.3

0

0

0

0

1

1

0.1

1

0.1

0

0

0

0

0

9

0.9

9

0.9

0

0

0

0

0

391

6.8

264

6.324

25

0.476

0

24

78

Individual Ballot Pool Results

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

NERC Standards

Ballot
Segment

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

Organization

Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Big Rivers Electric Corp.
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District

Member

Eric Scott
Paul B Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Chris Bradley
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Chang G Choi

Affirmative

Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative

Affirmative
Affirmative

Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative

Bob Solomon
Ajay Garg
Martin Boisvert
Molly Devine
Tino Zaragoza

Affirmative
Affirmative
Affirmative

Michael Moltane
Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Jennifer Flandermeyer
Stanley T Rzad
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Allan Long
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

NERC
Notes

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

New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Xcel Energy, Inc.

2

BC Hydro

2
2
2
2
2
2
2
2
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
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Alameda Municipal Power
Ameren Services
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
John Shaver
Noman Lee Williams
Howell D Scott
Steven Powell
Tracy Sliman
John Tolo
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Michelle Clements
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Douglas Draeger
Mark Peters
Chris W Bolick
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

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
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Bonneville Power Administration
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
City of Austin dba Austin Energy
City of Farmington
City of Redding
City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1

Rebecca Berdahl
Adam M Weber
Thomas C Duffy
Andrew Gallo
Linda R Jacobson
Bill Hughes
Bill R Fowler
Michelle A Corley
Charles Morgan
John Bee
Peter T Yost
Gerald G Farringer
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Lee Schuster
Danny Lindsey
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
Donald Hargrove
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

NERC Standards
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
4
4
4
4
4
4
4
4
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

South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power

Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Duane S Dahlquist
Reza Ebrahimian

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Tim Beyrle
Nicholas Zettel
John Allen

Affirmative
Affirmative

Margaret Powell

Affirmative

Tracy Goble
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Mark Ringhausen

Affirmative
Abstain
Negative
Affirmative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Steve Wenke
Clement Ma

Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative

Mike D Kukla

Affirmative

Francis J. Halpin
Shari Heino
Chifong Thomas
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
Marcus Ellis

Negative
Negative
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain

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

Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
PacifiCorp
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Chelan County
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
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.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Utility System Effeciencies, Inc. (USE)
Westar Energy
Western Farmers Electric Coop.
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Mike Garton
Dale Q Goodwine
Dan Roethemeyer

Affirmative
Affirmative
Affirmative

Dana Showalter
Gustavo Estrada
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

David Gordon

Affirmative

Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Bernard Johnson
Leo Staples
Mahmood Z. Safi
Bonnie Marino-Blair
Matt E. Jastram
Annette M Bannon
Tim Kucey
John Yale
Steven Grega

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain

Michiko Sell

Affirmative

Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Erika Doot
Robert L Dintelman
Bryan Taggart
Clem Cassmeyer
Linda Horn
Scott E Johnson
Liam Noailles

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
9
10
10
10
10
10

AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alcoa, Inc.

Massachusetts Attorney General
Commonwealth of Massachusetts Department
of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation

Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Luis Rodriguez
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Steve C Hill
Joseph O'Brien
Alan Johnson
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Peter H Kinney
David Hathaway
David F Lemmons
Thomas Gianneschi
Roger C Zaklukiewicz
Edward C Stein
Debra R Warner
Frederick R Plett

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative

Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Donald Nelson

Affirmative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

NERC Standards
10
10
10
10

SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Joseph W Spencer
Emily Pennel
Donald G Jones
Steven L. Rueckert

Legal and Privacy
 404.446.2560 voice  :  404.446.2595 fax  
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA  30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

Copyright © 2012 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=191b5685-09a5-4599-af96-b80ef264d301[8/9/2013 10:30:56 AM]

Affirmative
Affirmative
Affirmative
Affirmative

Consideration of Comments

Project 2010-13.2 Phase 2 Relay Loadability: Generation
PRC-023-3
The Project 2010-13.2 Phase 2 Relay Loadability: Generation standard drafting team thanks all
commenters who submitted comments on PRC-023-3. This standard was posted for a 45-day public
comment period from June 20, 2013 through August 8, 2013. Stakeholders were asked to provide
feedback on the standard and associated documents through a special electronic comment form. There
were 27 sets of comments, including comments from approximately 90 different people from
approximately 76 companies representing 9 of the 10 Industry Segments as shown in the table on the
following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process. If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary of Changes
Applicability
Sections 4.2.1.1, 4.2.2.1, and 4.2.2.2 were revised to clarify the applicability by removing
“except lines that are used exclusively to export energy directly from a Bulk Electric System
(BES) generating unit or generating plant to the network” and replacing it with “except
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant. Elements
may also supply generating plant loads.”
Implementation Plan
The phrase “load-responsive phase protection systems on” was inserted on Requirement R1,
R2, and R3 Applicability of the Implementation Plan to clarify that the “Applicability” column is
referring to the ownership of the relays applied on transmission lines and not the ownership of
the line. Requirement R6 was clarified that it includes Parts 6.1 and 6.2.

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Index to Questions, Comments, and Responses
If you support the comments submitted by another entity and would like to indicate you
agree with their comments, please select "agree" below and enter the entity's name
in the comment section (please provide the name of the organization, trade
association, group, or committee, rather than the name of the individual submitter).
........................................................................................................................ 8
1. The drafting team has modified the Applicability in PRC-023-3 to establish a bright
line between PRC-023-3 and PRC-025-1 by excluding lines that are used exclusively
to export energy directly from a BES generating unit or generating plant to the
network and GSU and in doing so included the DP and TO in PRC-025-1. Do you agree
that this establishes a bright line for the owners of load-responsive protective relays
applied these Facilities (i.e., except lines that are used exclusively to export energy
directly from a BES generating unit or generating plant to the network and GSUs)? If
not, provide specific detail that would improve the PRC-023-3 Applicability clarity or
any other comment. ......................................................................................... 9
END OF REPORT .......................................................................................................24

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 2 of 24

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

1.

Group

Guy Zito

Additional Member

Northeast Power Coordinating Council

Additional Organization

Region Segment Selection

1.

Alan Adamson

New York State Reliability Council, LLC NPCC 10

2.

Greg Campoli

New York Independent System Operator NPCC 2

3.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

4.

Ben Wu

Orange and Rockland Utilities

NPCC 1

5.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

6.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

7.

Kathleen Goodman

ISO - New England

NPCC 2

8.

Michael Jones

National Grid

NPCC 1

9.

David Kiguel

Hydro One Networks Inc.

NPCC 1

10. Christina Koncz

PSEG Power LLC

NPCC 5

11. Helen Lainis

Independent Electricity System Operator NPCC 2

12. Michael Lombardi

Northeast Power Coordinating Council

NPCC 10

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

16. Lee Pedowicz

NPCC

NPCC 10

17. Robert Pellegrini

The United Illuminating Company

NPCC 1

2

3

4

5

6

7

8

9

10

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

18. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

19. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

20. Brian Robinson

Utility Services

NPCC 8

21. Brian Shanahan

National Grid

NPCC 1

22. Wayne Sipperly

New York Power Authority

NPCC 5

23. Donald Weaver

New Brunswick System Operator

NPCC 2

2.

Group
Additional Member

Jason Marshall

2. John Shaver

Arizona Electric Power Cooperative

WECC 4, 5

3. John Shaver

Southwest Transmission Cooperative

WECC 1

4. Mark Ringhausen

Old Dominion Electric Cooperative

SERC

3, 4

5. Michael Brytowski

Great River Energy

MRO

1, 3, 5, 6

6. Shari Heino

Brazos Electric Power Cooperative

ERCOT 1, 5

7. Mohan Sachdeva

Buckeye Power

RFC

Additional Member

Robert Rhodes

Additional Organization

7

8

9

3, 4

X

Region Segment Selection
SPP

1, 4

2. Andy Evans

Westar Energy

SPP

1, 3, 5, 6

3. Louis Guidry

Cleco Power LLC

SPP

1, 3, 5

4. Stephanie Johnson Westar Energy

SPP

1, 3, 5, 6

5. Bo Jones

Westar Energy

SPP

1, 3, 5, 6

6. Tiffany Lake

Westar Energy

SPP

1, 3, 5, 6

7. James Nail

City of Independence Power & Light Department SPP

3

8. Lynn Schroeder

Westar Energy

SPP

1, 3, 5, 6

9. Kevin Stephan

Westar Energy

SPP

1, 3, 5, 6

David Thorne

6

X

SPP Standards Review Group

City Utilities of Springfield

Group

5

1, 3, 4, 5

1. John Allen

4.

4

Region Segment Selection

North Carolina Electric Membership Corporation SERC

Group

3

ACES Standards Collaborators

Additional Organization

1. David Sofra

3.

2

Pepco Holdings Inc & Affiliates

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley

Delmarva Power & Light Co RFC

1, 3

2. Alvin Depew

Pepco Holdings Inc

1, 3

5.

Group

Wayne Johnson

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

RFC

Southern Company: Southern Company
Services, Inc., Alabama Power Company,
Georgia Power Company, Gulf Power

X

X
Page 4 of 24

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

8

9

Company, Mississippi Power Company,
Southern Company Generation, Southern
Company Generation and Energy Marketing
No additional members listed.
6.
Group
David Greene
Additional Member

SERC Protection and Controls
Subcommittee

Additional Organization

1. Paul Nauert

Ameren

2. Steve Edwards

Dominion Virginia Power

3. Phil Winston

Southern Company Services

4. David Greene

SERC RRO

7.

Group
Additional Member

Region Segment Selection

Russel Mountjoy

MRO NERC Standards Review Forum (NSRF)

Additional Organization

1.

Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

2.

Dan Inman

Minnkota Power Cooperative

MRO

1, 3, 5, 6

3.

Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

4.

Keyleigh Wilkerson Lincoln Electric Systems

MRO

1, 3, 5, 6

5.

Jodi Jensen

Western Area Power Admininstration

MRO

1, 6

6.

Joseph DePoorter

Madison Gas and Electric

MRO

3, 4, 5, 6

7.

Ken Goldsmith

Alliant Energy

MRO

4

8.

Mahmood Safi

Omaha Public Power District

MRO

1, 3, 5, 6

9.

Marie Knox

Midcontinent Independent System Operator MRO

2

10. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

11. Scott Bos

Muscatine Power and Water

MRO

1, 3, 5, 6

12. Scott Nickels

Rochester Public Utilities

MRO

4

13. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

14. Tom Breene

Wisconsin Public Service

MRO

3, 4, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

8.

Group

Dennis Chastain

X

X

X

X

X

X

X

X

Region Segment Selection

Tennessee Valley Authority

X

X

Additional Member Additional Organization Region Segment Selection
1. DeWayne Scott

SERC

1

2. Ian Grant

SERC

3

3. David Thompson

SERC

5

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 5 of 24

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

4. Marjorie Parsons

SERC

6

5. Daniel McNeely

SERC

1

Group

9.

Louis Slade

Dominion

2

3

4

5

6

X

X

X

X

X
X
X

X
X
X

X
X
X

X
X
X

7

8

9

Additional Member Additional Organization Region Segment Selection
1. Jeff Bailey

Nuclear

2. Michael Crowley

Eletcric Transmission

SERC

1, 3

3. Chip Humphrey

Power Generation

SERC

5

4. Sean Iseminger

Power Generation

RFC

5

5. Matt Woodzell

Power Generation

NPCC 5

6. Mike Garton

NERC Compliance Policy NPCC 5, 6

7. Connie Lowe

NERC Compliance Policy SERC

1, 3, 5, 6

8. Randi Heise

NERC Compliance Policy RFC

5, 6

10.

11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.

Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual

Janet Smith,
Regulatory Affairs
Supervisor
Thomas Foltz\
Nazra Gladu
Don Weaver
Michelle D'Antuono
Michael Falvo
David Jendras
Travis Metcalfe
Alice Ireland
Brett Holland
Shaun Moran
Jonathan Meyer
Bill Fowler
Michael Lowman
Bradley Collard
Spencer Tacke
Ed O'Brien
Melissa Kurtz

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

5

Arizona Public Service Company
American Electric Power
Manitoba Hydro
New Brunswick System Operator
Occidental Energy Ventures Corp
Independent Electricity System Operator
Ameren
Tacoma Power
Xcel Energy
Kansas City Power & Light
NIPSCO
Idaho Power Co.
City of Tallahassee
Duke Energy
Oncor Electric Delivery Company LLC
Modesto Irrigation District
Modesto Irrigation District
US Army Corps of Engineers

X
X
X
X
X
X
X
X
X
X
X

X
X
X
X
X

X

X
X
X
X

X
X

X
X
X
X
X

X
X
X
X
X

X

X
X

X
X

Page 6 of 24

10

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 7 of 24

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade
association, group, or committee, rather than the name of the individual submitter).
Summary Consideration:
The SERC PCS comments suggested leaving PRC-023-2, Criterion 2.4 in the version three revision. The drafting team noted that
Criterion 2.4 is no longer necessary due to the revised Applicability. These relays are now applicable to the NERC Board of Trustees
adopted PRC-025-1 standard.

Organization
Ameren

Agree
Agree

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Supporting Comments of “Entity Name”
We agree with and support SERC PCS comments for
PRC-023-3.

Page 8 of 24

1.

The drafting team has modified the Applicability in PRC-023-3 to establish a bright line between PRC-023-3 and PRC-025-1 by
excluding lines that are used exclusively to export energy directly from a BES generating unit or generating plant to the
network and GSU and in doing so included the DP and TO in PRC-025-1. Do you agree that this establishes a bright line for the
owners of load-responsive protective relays applied these Facilities (i.e., except lines that are used exclusively to export
energy directly from a BES generating unit or generating plant to the network and GSUs)? If not, provide specific detail that
would improve the PRC-023-3 Applicability clarity or any other comment.

Summary Consideration:
All of the drafting team’s modifications to the proposed PRC-023-3 standard were non-substantive. Stakeholder majority comments
were limited to the Applicability section changes regarding how the drafting team implemented the phrase “except lines that are
used exclusively to export energy directly from a Bulk Electric System (BES) generating unit or generating plant to the network” rather
than “generator interconnection facilities.” Applicability comments were provided by approximately four entities and supported by as
many as 31 individuals. The drafting team remains steadfast in that the phrase “generator interconnection facilities” does not provide
the needed clarity for the facilities applicable to the standard; however, based on other similar comments, the drafting team
provided a non-substantive change to the three occurrences of the phrase “except lines that are used exclusively to export energy
directly from a Bulk Electric System (BES) generating unit or generating plant to the network” by replacing it with “except Elements
that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply generating plant loads.” This clarification also clarifies a minority
comment about how the original proposed language addressed conditions where those same interconnection lines also provided
station service or even cases where the generating plant was a pumped storage facility.
One comment supported by approximately 24 individuals requested clarification on in the implementation plan to clarify the
applicability is not the transmission line, but the ownership of the load-responsive protective relays. The drafting team made the
clarifying revision to the suggested Requirement R1 and also in Requirements R2 and R3 of the Implementation Plan.
The remaining comments were all minority concerns that did not result in a revision to the standard. Approximately three comments
supported by 18 individuals suggested changes to Requirement R2 of the proposed draft PRC-023-3 standard concerning out-of-step
blocking. The drafting team appreciates comments that improve the standard; however, this offered suggestion was outside the
scope of the drafting team’s effort to establish a bright line between the existing PRC-023-2 and the new PRC-025-1. There were a
few of comments regarding the PRC-023 standard’s criterion. For example, there was one comment representing about 8 individuals
suggesting to leave Requirement R1, Criterion 6 and Item 2.4 in Attachment A in the proposed PRC-023-3 standard. The drafting team
disagreed that these were no longer relevant to the standard as the criterion is now applicable to the NERC Board of Trustees
Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 9 of 24

adopted PRC-025-1 – Generator Relay Loadability standard. The same comment also suggested removing Requirement R1, Criterion
7; however, the drafting team disagreed because this criterion may be useful. One other comment represented by five individuals
supported the removal of 2.4 in Attachment A.
An additional minority comment supported by three individuals included a concern about the regulatory approval timeline of both
the proposed PRC-023-3 and the NERC Board of Trustees adopted PRC-025-1. The implementation plan of each standard, requires
that they both be approved by the regulatory authority together to avoid a reliability gap and compliance overlap. Two individuals
commented that the standard should only apply to generators and transformers that are material to the Bulk Electric System. The
drafting team noted that Elements such as generators or transformers that are demonstrated to be material to the BES will likely be
declared to be BES Elements under the provisions of the BES exception process. Other minority comments were editorial in nature by
single individuals and include capitalizing “system operator” in the Purpose of the standard, using a word other than “export” (i.e.,
“export energy”), adding “Requirement” inside the parenthetical numbered requirement at the end of each Measure, and an
observation about the posted redline to the previous posting of the standard being inaccurate. The drafting team did not make any
revisions based on these comments including not correcting the previously posted document.

Organization
ACES Standards Collaborators

Yes or No
No

Question 1 Comment
(1) The proposed changes are closer to establishing a bright line but still do
not go far enough.
(2) For consistency with Project 2010-07 Generator Requirements at the
Transmission Interface, we request using “generator interconnection Facility”
rather than “lines and transformers that are used exclusively to export
energy directly from a BES generating unit or generating plant to the
network”. While we understand the purpose of using the latter term is avoid
the implication that “generator interconnection Facility” is owned by the
Generator Owner, the latter term actually creates more confusion and will
likely lead to inconsistent enforcement. Furthermore, based on the
Guidelines and Technical Basis for PRC-025, the rationale for using the term
is only applicable to PRC-025 and not PRC-023. PRC-023 is already applicable
to the Distribution Provider so there is no need to expand applicability.

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 10 of 24

Organization

Yes or No

Question 1 Comment
Response: The drafting team made changes to PRC-025-1 during this
comment period to address these concerns. The drafting team made nonsubstantive changes to the PRC-023-3 Applicability 4.2.1.1, 4.2.2.1, and
4.2.2.2 to clarify the facility applicability. Change made.
The concern raised about the Distribution Provider’s applicability in PRC-0251 was addressed in the PRC-025-1 response to comments. No change made.
(3) Since the “generator interconnection Facility” term has already been
established in other standards and was deemed to be understood well
enough by industry that the Project 2010-07 Generator Requirements at the
Transmission Interface drafting team decided a glossary term was not
necessary contrary to the ad hoc report, the same terminology should be
used in PRC-023 to avoid confusion and inconsistency. Confusion could arise
with enforcement and compliance personnel over the use of the term “lines
and transformers that are used exclusively to export energy directly from a
BES generating unit or generating plant to the network” and how to apply
the standard to the GO. This will result in the GO, NERC and Regional Entities
expending resources on unnecessary compliance activities that do not
support reliability.
Response: The drafting team notes that previous stakeholder comments
revealed that the phrase “generator interconnection facility” was unclear
and led the team to revising the applicability not to use the phrase. No
change made.
(4) For PRC-023, we further request that the “generator interconnection
Facility” term be further refined to “non-radial generator interconnection
Facility” or “networked generator interconnection Facility”. From the
Guideline and Technical Basis document for PRC-025, we understand that
PRC-023 is applicable to the GO because some “generation interconnection
Facilities” are networked as shown in Figure 3 of the document. Figure 3
depicts a common situation in which a generator that was looped into an

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 11 of 24

Organization

Yes or No

Question 1 Comment
existing line such that current can flow from the grid through the high side
bus of the generator step up transformer back to the grid. This additional
refinement is needed to clarify in what limited situations PRC-023 would be
applicable to the Generator Owner.
(5) We request that applicability section 4.1.2 be modified to clarify it is only
applicable to Generator Owners that own networked or non-radial “lines and
transformers that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network” or “generator
interconnection Facilities”.
Response (Items 4 & 5): The drafting team made non-substantive changes to
the PRC-023-3 Applicability 4.2.1.1, 4.2.2.1, and 4.2.2.2 to clarify the facility
applicability. Change made.
(6) We understand that the term “lines and transformers that are used
exclusively to export energy directly from a BES generating unit or generating
plant to the network” was used in PRC-023 because the Guidelines and
Technical Basis document indicated there was a concern that a Distribution
Provider may own a “generation interconnection Facility” and that the term
implies ownership by the GO. We disagree with this implication and we have
found numerous references including the November 16, 2009 Final Report
from the Ad Hoc Group for Generator Requirements at the Transmission
Interface that indicate the facility may or may not be owned by the GO.
Furthermore, the original proposed definition of a “generation
interconnection Facility” from the report did not indicate ownership.
Response: The drafting team notes that previous stakeholder comments
revealed that the phrase “generator interconnection facility” was unclear
and led the team to revising the applicability not to use the phrase. No
change made.
(7) While we understand the intended use of the term “except lines and

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 12 of 24

Organization

Yes or No

Question 1 Comment
transformers that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network” was used in PRC-025
because of the drafting team’s concern of the implication of GO ownership
would prevent applicability to the DP, we find it is unnecessary in PRC-023.
PRC-023 is already otherwise applicable to PRC-023 because a DP might own
Transmission Protection Systems as identified in the NERC compliance
registry. If the DP did own networked “generation interconnection Facility”
above the 100 kV threshold compliance registry criteria, they would be
registered as a Transmission Owner as well. Furthermore, PRC-023 R6 would
still allow the PC to identify networked facilities below 100 kV that the DP
owns.
Response: The Distribution Provider is included to address those cases where
a Distribution Provider owns load-responsive protective relays on the
Elements listed in the Applicability section of the standard. This also avoids an
entity having to register as a Transmission Owner for this specific condition.
No change made.
(8) There are inconsistencies between the terms in PRC-023 and PRC-025
that are intended to apply to non-radial and radial generator interconnection
Facilities. PRC-025 uses the term “Elements that connect a GSU transformer
to the Transmission system that are used exclusively to export energy
directly from a BES generating unit or generating plant” while PRC-023 uses
slight variants of the term “except lines and transformers that are used
exclusively to export energy directly from a BES generating unit or generating
plant to the network”. Some differences that should be eliminated include
the appended “to the network” in the PRC-023 term, use of “Elements” in
PRC-025, and use of “lines and transformers”.
Response: The drafting team made non-substantive changes to the PRC-0233 Applicability 4.2.1.1, 4.2.2.1, and 4.2.2.2 to eliminate the noted
inconsistencies. Change made.

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 13 of 24

Organization

Yes or No

Question 1 Comment

Response: The drafting team thanks you for your comments; please see the above responses.
NIPSCO

No

Summary of added clarification: this entity suggests that clarification of
requirements is needed for Requirement 2 (R2) with regards to "out-of-step
blocking" since this "out of step blocking" function may or may not be
implemented on every BES facilties' protection scheme and should be held
under the judgment of the protection and control engineer. Some may read
the existing standard requirement R2 wording as “an explicit requirement to
indeed set "out of step blocking" elements on all protective relays equipped
with the element as an option, set in the manner described in R2”. This is
assumed not to be the intention by the wording of the standard. We suggest
the following:
R2. Each Transmission Owner, Generator Owner, and Distribution
Provider shall set its out-of-step blocking elements[, if implemented, ]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]

Response: The drafting team thanks you for your comments and notes this suggestion is out of scope of the project. No change
made.
Modesto Irrigation District

No

I am voting NO on this revision to this NERC Standard, because I would
suggest the following changes be made:
1. Section 4.2.1.3 (under "Circuits Subject to Requirements R1 - R5") needs
be revised to read "Transmission lines operated below 100 kV that have been
shown to have a material impact to the reliability of the adjacent
interconnected system, or as selected by the Planning Authority in
accordance with Requirement R6".

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 14 of 24

Organization

Yes or No

Question 1 Comment
2. Section 4.2.1.6 (under "Circuits Subject to Requirements R1 - R5") needs
be revised to read "Transformers with low voltage terminals connected
below 100 kV that have been shown to have a material impact to the
reliability of the adjacent interconnected system, or as selected by the
Planning Authority in accordance with Requirement R6". Thank you.

Response: The drafting team thanks you for your comments and notes that Elements such as generators or transformers that are
demonstrated to be material to the BES will likely be declared to be BES Elements under the provisions of the BES exception process;
therefore, will be made applicable to the standard. No change made.
Modesto Irrigation District

No

1. Section 4.2.1.3 (under "Circuits Subject to Requirements R1 - R5") needs
be revised to read "Transmission lines operated below 100 kV that have been
shown to have a material impact to the reliability of the adjacent
interconnected system, or as selected by the Planning Authority in
accordance with Requirement R6".
2. Section 4.2.1.6 (under "Circuits Subject to Requirements R1 - R5") needs
be revised to read "Transformers with low voltage terminals connected
below 100 kV that have been shown to have a material impact to the
reliability of the adjacent interconnected system, or as selected by the
Planning Authority in accordance with Requirement R6".

Response: The drafting team thanks you for your comments and notes that Elements such as generators or transformers that are
demonstrated to be material to the BES will likely be declared to be BES Elements under the provisions of the BES exception process;
therefore, will be made applicable to the standard. No change made.
Northeast Power Coordinating Council

Yes

Other comments:
Most, if not all of the lines being excluded from the Standard could still be
utilized to provide station service supply to the generating plant. Are any
lines used “exclusively” to export energy from a BES GO? Would lines used
to supply station service load at generating plants (for example during

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 15 of 24

Organization

Yes or No

Question 1 Comment
generator shutdown) still be excluded from PRC-023-3?
Response: The drafting team made non-substantive changes to the PRC-0233 Applicability 4.2.1.1, 4.2.2.1, and 4.2.2.2 to clarify the facility applicability.
Change made.
From the Applicability for R1 on page 3 of the Implementation Plan for PRC023-3 should be revised from “Each Transmission Owner, Generator Owner
and Distribution Provider with transmission lines operating at...” to “Each
Transmission Owner, Generator Owner and Distribution Provider with loadresponsive protection systems on transmission lines operating at...” The
transmission line owner and load-responsive relay owner could be
represented by two or more different entities. The owner of the loadresponsive protection system should be responsible for compliance as
identified properly under Section 4, Applicability of PRC-023-3. The
Implementation Plan should not contradict Applicability or the Requirements
set forth in the Standard.
Response: The drafting team made the suggested non-substantive edits to
clarify the implementation plan that applicability is based on the ownership
of the relays. Change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Pepco Holdings Inc & Affiliates

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Yes

We agree with all the proposed changes to PRC-023-3. However, we have
concerns with the proposed implementation plan for PRC-023-3 and the
proposed retirement date of PRC-023-2. The entire PRC-023-2 standard
should remain in force until the effective date of PRC-025-1, not just
Requirement R1, Criterion 6. This is because PRC-023-2 also includes
generator protection relays that are susceptible to load (PRC-023-2
Attachment A, Section 2.4). If PRC-023-2 is retired and PRC-023-3 becomes
effective prior to the full implementation of PRC-025-1 there could be a gap

Page 16 of 24

Organization

Yes or No

Question 1 Comment
in compliance associated with generator protection relays previously subject
to PRC-023-2. As such, we believe the implementation of PRC-025-1 and PRC023-3 as well as the retirement of PRC-023-2 should all be coincident.

Response: The drafting team thanks you for your comment and notes that the Implementation Plan for both PRC-023-3 and PRC-0251 dictate that both need to be approved simultaneously by regulators to avoid the described gap. No change made.
Southern Company: Southern Company
Services, Inc., Alabama Power Company,
Georgia Power Company, Gulf Power
Company, Mississippi Power Company,
Southern Company Generation,
Southern Company Generation and
Energy Marketing

Yes

1) We endorse the SERC Protection & Control Subcommittee (PCS)
comment: Please include, rather than remove, 2.4 in Attachment A
(“Protective relays applied at the terminals of generation Facilities...”)
because this reinforces the bright line between PRC-023-3 and PRC-025-1;
Response: The drafting team contends that Criterion 2.4 is no longer
necessary due to the revised Applicability. These relays are now applicable to
the NERC Board of Trustees adopted PRC-025-1 standard. No change made.
2) We have an observation regarding terminology between terms used in
PRC-023-3 and PRC-025-1: The Transmission standard discusses 'electrical
network' and 'the network' in the Purpose and Applicability (See Part A.
4.2.1.1, 4.2.2.1, and 4.2.2.2) while the Generator standard discusses
'Transmission system' at the Applicability section 3.2.4. Should these terms
all be the same?
Response: The drafting team made non-substantive changes to the PRC-0233 Applicability 4.2.1.1, 4.2.2.1, and 4.2.2.2 to eliminate the noted
inconsistencies. Change made.
3) We feel that all the transmission line terminal setting criteria should have
remained in PRC-023.
Response: The drafting team notes that Criterion 6 was removed (i.e., “Not
used”) because it is no longer applicable to the standard based on the
changes made to align PRC-023-3 with PRC-025-1. No change made.

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 17 of 24

Organization

Yes or No

Question 1 Comment

Response: The drafting team thanks you for your comments; please see the above responses.
SERC Protection and Controls
Subcommittee

Yes

Please include, rather than remove, 2.4 in Attachment A (“Protective relays
applied at the terminals of generation Facilities...”) because this reinforces
the bright line between PRC-023-3 and PRC-025-1.
The comments expressed herein represent a consensus of the views of the
above-named members of the SERC EC Protection and Control
Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.

Response: The drafting team thanks you for your comment and contends that Criterion 2.4 is no longer necessary due to the revised
Applicability. These relays are now applicable to the NERC Board of Trustees adopted PRC-025-1 standard. No change made.
MRO NERC Standards Review Forum
(NSRF)

Yes

The NSRF agrees that this revision of PRC-023-3 establishes a bright line for
load-responsive relay owners between generating units and transmission
networks. The following is an additional comment regarding PRC-023-3
content:
The requirements in R2 with regard to out-of-step blocking are not
supported in the technical reference document. Out-of-step relaying does
not seem to fall under the purpose of the PRC-023-3 as it is suggested they
do not “limit transmission loadability.” For these reasons requirement R2
should be deleted.

Response: The drafting team thanks you for your comment and notes this suggestion is out of scope of the project. No change
made.
Manitoba Hydro

Yes

Although Manitoba Hydro is in general agreement with the standard, we
have the following comments
(1) Purpose - for clarity, consider replacing the words “system operators’”

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Page 18 of 24

Organization

Yes or No

Question 1 Comment
with [a System Operator(s)”].
Response: The drafting team that originally developed the PRC-023 standard
intended the term “system operators” to be used in the more general use
rather than the more definite NERC Glossary term. No change made.
(2) Measures (M1-M6) - for consistency with the Data Retention section,
consider adding the word [Requirement] before the bracketed requirements
- R1, R2, R3, R4, R5 and R6 found at the end of each of the measures.
Response: The drafting team considered the suggestion and elected not to
make the editorial suggestion in the Measures where each requirement is
linked parenthetically to an actual Requirement. Such changes would not be
consistent with the body of standards that use this convention. No change
made.
(3) PRC 023-3, Sections 4.2.1.1 and 4.2.2.1 - have been revised to exclude
lines and transformers that are used exclusively to “export” energy directly
from a Bulk Electric System (BES) generating unit to the network. Use of the
term “export” implies that the energy is delivered from one government
jurisdiction to a foreign jurisdiction. It is not clear why such a term would be
used. Unless this was the actual intention, the term “export” should be
replaced with [transmit] or [deliver].
Response: The drafting team made non-substantive changes to the PRC-0233 Applicability 4.2.1.1, 4.2.2.1, and 4.2.2.2 to clarify the facility applicability.
Change made.
The drafting team notes that the understanding of the term “export energy”
may be slightly different. The term “export energy” is synonymous with
“deliver” or “transmit.” No change made.
(4) Implementation Plan - In the Implementation Plan chart for R6, the
“Applicability” section does not describe the applicable entities for the
requirement. Instead, it describes part of the requirement. The Applicable

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

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Organization

Yes or No

Question 1 Comment
entities should be identified. Also, as drafted only one part of the
requirement is addressed by the Implementation Plan chart. If the intent is to
create 2 different effective dates for different parts of R6, this should be
specified in the first column.
Response: The drafting team notes that the only update to the
Implementation Plan was to include the known dates as a reference for
industry. Additionally, the drafting team had no specific reason to address
changes in the language of the plan because the performance of the
requirements was not changing with regard to transmission relays. The
drafting team recognizes after reviewing the comment above that the R6
“Applicability” text in the Implementation Plan reads more like the actual
Requirement R6 language; whereas, the Applicability text for requirements
R1-R5 are more generic and relates to the entities and circuits identified in
the PRC-023-3 Applicability section.
Since the Implementation Plan is materially the same as the plan approved
with version two of the PRC-023-3 standard and that the drafting team has
not received earlier concern about the language, the drafting team decided
not to revise the text. The drafting team does offer that the style and manner
the Implementation Plan is written, the time periods associated with R6 do
include its sub-parts 6.1 and 6.2. No change made.

Response: The drafting team thanks you for your comments; please see the above responses.
Occidental Energy Ventures Corp

Yes

Occidental Energy Ventures Corp. believes that the project team has taken a
far more elegant approach in separating relays designed to protect
transmission equipment from those protecting generation equipment without regard to the relay owner. The previous method required criteria
duplicated from PRC-025-1, which was difficult to follow.
With multiple other generator protection system standards pending -

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

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Organization

Yes or No

Question 1 Comment
including Phase III development of Project 2010-13 - we would like to see a
regulatory commitment to a comprehensive risk-based Compliance approach
to the topic. We share NERC’s concern that Misoperations continue to be a
leading cause of BES events; due in major part to the complex interaction of
Protection System schema. In this model, the settings criteria in all PRC
standards must be continually evaluated against event data - which NERC is
just beginning to accumulate. This means that those standards which do not
show progress in reducing BES risk, must be aggressively withdrawn in favor
of those which do. Only then can we be comfortable that the most effective
critieria is in place.

Response: Thank you for your comment. Monitoring, analyzing, and tracking trends in Protection System Misoperations are critical
to improving BES reliability. Misoperation data collection provides several benefits to BES reliability and supports NERC’s mission of
ensuring the reliability of the BPS. NERC is committed to working with stakeholders to provide high value risk analysis with the goal
of identifying areas for improvement in Misoperation rates and supporting comprehensive solutions. NERC is obligated to conduct
five-year reviews of standards that are more than five years old and have not yet been revised through other standards
development projects. Within the next year, all standards that have not been significantly revised or retired will undergo a
comprehensive review to determine whether the standard should be reaffirmed, revised, or withdrawn. NERC has responded to
regulatory and industry guidance by incorporating into its five-year review process principles of results-based standards drafting and
a review of each standard in relation to other standards to eliminate duplicative requirements. Additionally, five-year reviews will
evaluate whether each standard is clear, concise, and technically sound given current technologies and system conditions, whether
any regulatory directives require specific changes to the standard, and whether the requirements that do little to ensure the
reliability of the BPS should be eliminated. Five-year reviews also will consider previously captured stakeholder-identified issues
pertaining to the affected standards. No change made.
Tacoma Power

Yes

On page 14 of the redlined Implementation Plan for PRC-023-3, 4.2.3 and
4.2.4 in Proposed Replacement column should be deleted.

Response: The drafting team thanks you for identifying this error. A manual redline, rather than an automatic one, was created for
clarity. Automatic redlining does not always yield the best mark-up and therefore makes understanding the changes difficult; while
manual redlining tends to introduce errors in attempting to make the changes more apparent. No change made will be made to the
Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

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Organization

Yes or No

Question 1 Comment

previously posted redline. The clean version that was posted contemporaneously with the redline version was correct. No change
made.
Xcel Energy

Yes

Xcel Energy believes Requirement 1, Criteria 7 should be removed from the
standard. It does not have an application with the addition ‘except lines that
are used exclusively to export energy directly from a Bulk Electric System
(BES) generating unit or generating plant to the network’ to Applicability
4.2.1.1.

Response: The drafting team thanks you for your comment and contends that Criterion 7 may still be useful. No change made.
Kansas City Power & Light

Yes

In the Implementation Plan, page 14, 4.2.3 and 4.2.4 are shown in the
proposed replacement column. 4.2.3 and 4.2.4 refer to Requirements R7 and
R8 which have been removed. The text is not included in the already
approved standard and is not red-lined in the proposed replacement column,
so I imagine that this was pasted in accidentally.

Response: The drafting team thanks you for identifying this error. A manual redline, rather than an automatic one, was created for
clarity. Automatic redlining does not always yield the best mark-up and therefore makes understanding the changes difficult; while
manual redlining tends to introduce errors in attempting to make the changes more apparent. No change made will be made to the
previously posted redline. The clean version that was posted contemporaneously with the redline document was correct. No change
made.
Duke Energy

Yes

Duke Energy agrees that the modifications implemented by the drafting
team creates the necessary bright line between PRC-023-1 and PRC-025-1.

Response: The drafting team thanks you for your comment.
Oncor Electric Delivery Company LLC

Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

Yes

The word “exclusively” should be changed to “primarily” as these
interconnect lines are also used to import power during non-generation
periods.

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Organization

Yes or No

Question 1 Comment

Response: The drafting team thanks you for your comment and notes it made non-substantive changes to the PRC-023-3 Applicability
4.2.1.1, 4.2.2.1, and 4.2.2.2 to clarify the facility applicability. Change made.
US Army Corps of Engineers

Yes

The requirements in R2 with regard to out-of-step blocking are not
supported in the technical reference document. Out-of-step relaying does
not seem to fall under the purpose of the PRC-023-3 as it is suggested they
do not “limit transmission loadability.” For these reasons requirement R2
should be deleted.

Response: The drafting team thanks you for your comment and notes this suggestion is out of scope of the project. No change
made.
Tennessee Valley Authority

Yes

Dominion

Yes

Arizona Public Service Company

Yes

American Electric Power

Yes

New Brunswick System Operator

Yes

Independent Electricity System Operator

Yes

Idaho Power Co.

Yes

City of Tallahassee

Yes

SPP Standards Review Group

Yes

Ameren
Consideration of Comments: Project 2010-13.2
PRC-023-3 | August 15, 2013

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END OF REPORT

Consideration of Comments: Project 2010-13.2
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Standard PRC-023-3 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for a 45-day informal comment period from January
25, 2013 to March 11, 2013 along with a red-lined Draft 1 of the revised standard.
3. Draft 2 of the revised standard was posted for a 30-day formal comment period from April 25,
2013 to May 24, 2013.

4. Draft 3 of the revised standard was posted for a 45-day formal comment period from June
20, 2013 to August 8, 2013 and an initial ballot in the last 10 days of the comment period.
Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 4 of
PRC-023-3 – Transmission Relay Loadability for a 10-day recirculation ballot.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

June 2013

10-day Recirculation Ballot

August 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version
1

Date
February 12,
2008

Action
Approved by Board of Trustees

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Change
Tracking
New

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Standard PRC-023-3 — Transmission Relay Loadability

Version

Change
Tracking

Date

Action

1

March 19, 2008

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

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Errata

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title:

Transmission Relay Loadability

2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinator
4.2. Circuits:
4.2.1 Circuits Subject to Requirements R1 – R5:
4.2.1.1 Transmission lines operated at 200 kV and above, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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
Requirement 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, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.

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Standard PRC-023-3 — Transmission Relay Loadability
4.2.2.2 Transmission lines operated below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES, except
Elements that connect the GSU transformer(s) to the Transmission system
that are used exclusively to export energy directly from a BES generating
unit or generating plant. Elements may also supply generating plant loads.
5. Effective Dates: See Implementation Plan.
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 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, 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. Not used.

1

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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

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 capability2.

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 3.

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.

2

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.
3

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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)

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Standard PRC-023-3 — 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 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 PRC-023-3, 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)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. 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:

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Standard PRC-023-3 — Transmission Relay Loadability
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 Requirement 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 Requirement 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 Enforcement Authority 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.

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Standard PRC-023-3 — Transmission Relay Loadability

2.
Requirement

R1

Violation Severity Levels:
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 BES 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.

R2

R3

N/A

N/A

N/A

N/A

Project 2010-13.2 Phase 2 Relay Loadability (Draft 4: August 15, 2013)

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

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 7, 8, 9,
12, or 13 did not use the calculated
circuit capability as the Facility
Rating of the circuit.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

Project 2010-13.2 Phase 2 Relay Loadability (Draft 4: August 15, 2013)

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.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

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High
months or more 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 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)

Severe
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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

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Standard PRC-023-3 — 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

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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. Not used.
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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 Bulk
Electric System.

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 Interconnection Reliability Operating Limit (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 4 performed by the Planning Coordinator for the one-tofive-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.
4

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

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Standard PRC-023-3 — Transmission Relay Loadability
d. The threshold for selection of the circuit 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.

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.

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Standard PRC-023-3 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for a 45-day informal comment period from January
25, 2013 to March 11, 2013 along with a red-lined Draft 1 of the revised standard.
3. Draft 2 of the revised standard was posted for a 30-day formal comment period from April 25,
2013 to May 24, 2013.

4. Draft 3 of the revised standard was posted for a 45-day formal comment period from June
20, 2013 to August 8, 2013 and an initial ballot in the last 10 days of the comment period.
Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 34 of
PRC-023-3 – Transmission Relay Loadability for a 4510-day formal comment period and
initialrecirculation ballot.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

June 2013

10-day Recirculation Ballot

August 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version
1

Date
February 12,
2008

Action
Approved by Board of Trustees

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Change
Tracking
New

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Standard PRC-023-3 — Transmission Relay Loadability

Version

Change
Tracking

Date

Action

1

March 19, 2008

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

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Errata

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-3 — Transmission Relay Loadability
A. Introduction
1. Title:

Transmission Relay Loadability

2. Number:

PRC-023-3

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 Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection systems as described in
PRC-023-3 - Attachment A, applied at the terminals of the circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinator
4.2. Circuits:
4.2.1 Circuits Subject to Requirements R1 – R5:
4.2.1.1 Transmission lines operated at 200 kV and above, except linesElements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a Bulk Electric System (BES)
generating unit or generating plant to the network. Elements may also supply
generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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
Requirement 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, except lines and
transformersElements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly from

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Standard PRC-023-3 — Transmission Relay Loadability
a BES generating unit or generating plant to the network. Elements may also
supply generating plant loads.
4.2.2.2 Transmission lines operated below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES, except
lines and transformersElements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly from
a BES generating unit or generating plant to the network. Elements may also
supply generating plant loads.
5. Effective Dates: See Implementation Plan.
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 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, criterion 3, using the full line inductive
reactance.

1

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.

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Standard PRC-023-3 — 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. Not used.
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

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 capability2.

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 3.

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.

2

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.
3

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.

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 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 PRC-023-3, 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-023-3 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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

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Standard PRC-023-3 — Transmission Relay Loadability
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 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 PRC-023-3, 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)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Data Retention

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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 Requirement 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 Requirement 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 Enforcement Authority 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.

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Standard PRC-023-3 — Transmission Relay Loadability

2.
Requirement

R1

Violation Severity Levels:
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 BES 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.

R2

R3

N/A

N/A

N/A

N/A

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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

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 7, 8, 9,
12, or 13 did not use the calculated
circuit capability as the Facility
Rating of the circuit.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

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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.

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

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High
months or more 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 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)

Severe
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

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Standard PRC-023-3 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

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Standard PRC-023-3 — 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

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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. Not used.
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.

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Standard PRC-023-3 — Transmission Relay Loadability
PRC-023-3 — 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 Bulk
Electric System.

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 Interconnection Reliability Operating Limit (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 4 performed by the Planning Coordinator for the one-tofive-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.
4

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

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Standard PRC-023-3 — Transmission Relay Loadability
d. The threshold for selection of the circuit 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.

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.

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Standard PRC-023-23 — Transmission Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the Supplemental SAR regarding PRC-023-2 for
posting on January 16-17, 2013.
2. The Supplemental SAR was posted for a 45-day informal comment period from January
25, 2013 to March 11, 2013 along with a red-lined Draft 1 of the revised standard.
3. Draft 2 of the revised standard was posted for a 30-day formal comment period from April 25,
2013 to May 24, 2013.

4. Draft 3 of the revised standard was posted for a 45-day formal comment period from June
20, 2013 to August 8, 2013 and an initial ballot in the last 10 days of the comment period.
Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 4 of
PRC-023-3 – Transmission Relay Loadability for a 10-day recirculation ballot.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 2013

45-day Formal Comment Period and Initial Ballot

June 2013

10-day Recirculation Ballot

August 2013

BOT adoption

November 2013

File with FERC

December 2013

Effective Dates
See PRC-023-3 Implementation Plan.
Version History
Version
1

Date
February 12,
2008

Action
Approved by Board of Trustees

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Change
Tracking
New

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Standard PRC-023-23 — Transmission Relay Loadability

Version

Change
Tracking

Date

Action

1

March 19, 2008

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

1

March 18, 2010

Approved by FERC

1

Filed for
approval April
19, 2010

Changed VRF for R3 from Medium to
High; changed VSLs for R1, R2, R3 to
binary Severe to comply with Order 733

Revision

2

March 10, 2011
approved by
Board of
Trustees

Revised to address initial set of directives
from Order 733

Revision (Project
2010-13)

2

March 15, 2012

FERC order issued approving PRC-023-2
(approval becomes effective May 7, 2012)

3

TBD

Clarify applicability for consistency with
PRC-025-1 and other minor corrections

Errata

Supplemental SAR
(Project 2010-13.2)

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

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Standard PRC-023-23 — Transmission Relay Loadability
A. Introduction
1. Title:

Transmission Relay Loadability

2. Number:

PRC-023-23

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-023-23 - Attachment A, applied toat the terminals of the 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-023-23 - Attachment A, applied toat the terminals of the 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-023-23 - Attachment A, applied toat the terminals of the circuits defined in
4.2.1 (Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional 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, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with Requirement 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 Requirement 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 Requirement 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
Requirement 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, except Elements that
connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads.

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Standard PRC-023-23 — Transmission Relay Loadability
4.2.2.2 Transmission lines operated below100below 100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES
5.

Effective Dates
5.1.1.14.2.2.2
The effective dates of, except Elements that connect the
requirements in the PRC-023-2 standard correspondingGSU transformer(s)
to the applicable Functional Entities and circuitsTransmission system that are
summarized in the following table:used exclusively to export energy directly
from a BES generating unit or generating plant. Elements may also supply
generating plant loads.

5. Effective Dates: See Implementation Plan.
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 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, criterion 3, using the full line inductive
reactance.

1

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.

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Standard PRC-023-23 — 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.
6. Not used.
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

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 capability2.

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 3.

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:

2

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.
3

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.

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Standard PRC-023-23 — Transmission Relay Loadability
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 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 PRC-023-3, 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-023-23 per application of Attachment B, including
identification of the first calendar year in which any criterion in PRC-023-3, 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.

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Standard PRC-023-23 — Transmission Relay Loadability
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, 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 PRC-023-3, 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)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
1.2.1.1.
For entities that do not work for the Regional Entity, the Regional Entity shall
serve as the Compliance Enforcement Authority.

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Standard PRC-023-23 — Transmission Relay Loadability
For functional entities that work for their Regional Entity, the ERO shall serve as the As
defined in the NERC Rules of Procedure, “Compliance Enforcement Authority. ” means
NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.3.1.2. 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 Requirement 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 Requirement 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 MonitorEnforcement Authority shall keep the last audit record and all
requested and submitted subsequent audit records.
1.4.1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.5.1.4. Additional Compliance Information
None.

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Standard PRC-023-23 — Transmission Relay Loadability

2.
Requirement

R1

Violation Severity Levels:
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 SystemBES 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.

R2

R3

N/A

N/A

N/A

N/A

Project 2010-13.2 Phase 2 Relay Loadability (Draft 4: Au g u s t 15, 2013)

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

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.

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Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate

High

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

R4

R5

R6

N/A

N/A

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.
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

N/A

N/A

N/A

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

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 24

Project 2010-13.2 Phase 2 Relay Loadability (Draft 4: Au g u s t 15, 2013)

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.

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Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate
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.

Project 2010-13.2 Phase 2 Relay Loadability (Draft 4: Au g u s t 15, 2013)

High
months or more 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 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)

Severe
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

11 of 16

Standard PRC-023-23 — Transmission Relay Loadability

Requirement

Lower

Moderate
(part 6.2)

High

Severe
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 the standard.

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Standard PRC-023-23 — 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
.

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Standard PRC-023-23 — Transmission Relay Loadability
PRC-023-3 — 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.
2.4. Not used.
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.

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Standard PRC-023-23 — Transmission Relay Loadability
PRC-023-3 — 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 BESBulk Electric System.

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,Interconnection Reliability Operating Limit
(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 4 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.

4

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

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Standard PRC-023-23 — 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.

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16 of 16

Implementation Plan

PRC-023-3 – Transmission Relay Loadability
Project 2010-13.2 Phase II Relay Loadability
Requested Approvals

•

PRC-023-3 – Transmission Relay Loadability

Requested Retirements

•

PRC-023-2 – Transmission Relay Loadability

Prerequisite Approvals

•

PRC-025-1 – Generator Relay Loadability*
*A supplemental SAR was approved by the Standards Committee at their January 16-17, 2013 meeting to
authorize the drafting team to make changes to PRC-023-2 to comport with the proposed draft PRC-0251 – Generator Relay Loadability in order to establish a bright line between the applicability of loadresponsive protective relays in the current transmission and the proposed generator relay loadability
standards.

Revisions to Defined Terms in the NERC Glossary

•

None

Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is
no bright line to clearly distinguish which load-responsive protective relays pertain to the existing PRC-023-2 –
Transmission Relay Loadability standard, effective in the United States on July 1, 2012, and the proposed PRC025-1 – Generator Relay Loadability standard. To resolve this concern, the drafting team proposed to modify
the applicability section of PRC-023-2. The standard drafting team clarified, for each functional entity, the
applicability of PRC-023-2 by tying applicability to the terminal the load-responsive protective relay that it is
connected to within the Transmission system.

General Considerations

It is expected that the implementation period for PRC-023-2 will have been achieved, in part, by the time PRC023-3 is adopted by the NERC Board of Trustees and by the time of other approvals by applicable

governmental authorities. The proposed PRC-023-3 Implementation Plan now reflects specific milestone dates
that are known time periods consistent with PRC-023-2.
Applicable Entities

•

Distribution Provider

•

Generator Owner

•

Planning Coordinator

•

Transmission Owner

Effective Date
New Standard

PRC-023-3

First day of the first calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the
first day of the first calendar quarter beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.

Standards for Retirement

PRC-023-2

Midnight of the day immediately prior to the Effective Date of PRC-023-3 –
Transmission Relay Loadability in the particular jurisdiction in which the new
standard is becoming effective, except Requirement R1, Criterion 6 which will
remain in force until the effective date of PRC-025-1.

Implementation Plan for Definitions

No definitions are proposed as a part of this standard.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

2

Implementation Plan for PRC-023-3, Requirements R1 through R6

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to
this standard shall be 100% compliant on the following dates:
Implementation Date
Requirement

Applicability

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on transmission lines operating
at 200 kV and above and transformers
with low voltage terminals connected at
200 kV and above, except as noted
below.

R1

•

•

For supervisory elements as
described in PRC-023-3 - Attachment
A, Section 1.6

For switch-on-to-fault schemes as
described in PRC-023-3 - Attachment
A, Section 1.3

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

The later of July 1,
2014 or first day of the
first calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

3

Implementation Date
Requirement

R1
(continued)

R2 and R3

Applicability

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

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on transmission lines operating
at 200 kV and above and transformers
with low voltage terminals connected at
200 kV and above

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

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 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

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 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

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

4

Implementation Date
Requirement

R2 and R3
continued

R4

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on 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 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

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 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 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 Board of
Trustees adoption, or
First day of the first
as otherwise made
calendar quarter six
months after applicable effective pursuant to
the laws applicable to
regulatory approvals
such ERO
governmental
authorities

Applicability

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

5

Implementation Date
Requirement

R5

R6
(including
parts 6.1 and
6.2)

Applicability

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

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 Owner,
and Distribution Providers must comply
with Requirements R1 through R5

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Later of January 1,
2014 or the first day of
the first calendar
quarter after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

6

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is
implemented. If the drafting team is recommending revisions, those changes are identified by the “Proposed Replacement” column.
Already Approved Standard
PRC-023-2
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

Proposed Replacement
PRC-023-3
4.1. Functional Entity
4.1.1 Transmission Owner with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.2 Generator Owner with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.3 Distribution Provider with load-responsive phase protection
systems as described in PRC-023-3 - Attachment A, applied at the
terminals of the circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5), provided those circuits have bi-directional flow
capabilities.
4.1.4 Planning Coordinator

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1, Functional Entity creates a bright line between those load-responsive
protective relays that are applicable to PRC-023-3 – Transmission Relay Loadability and the proposed PRC-025-1 – Generator Relay Loadability.
This is evident by the minor changes to the Applicability text to distinguish the applicability of the relays by which “terminal” the load-responsive
protective relay is connected to within the Transmission system. Applicability is established by ownership of the load-responsive protective
relays, not the Facilities.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

7

Already Approved Standard

Proposed Replacement

PRC-023-2
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.

PRC-023-3
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above, except
Elements that connect the GSU transformer(s) to the Transmission
system that are used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply
generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the
Planning Coordinator in accordance with Requirement 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
Requirement 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
Requirement 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 Requirement R6.

4.2.2 Circuits Subject to Requirement R6

4.2.2 Circuits Subject to Requirement R6

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

8

Already Approved Standard

Proposed Replacement

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 below 100 kV and transformers
with low voltage terminals connected below 100 kV that are part of the
BES

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, except Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant. Elements may also
supply generating plant loads.
4.2.2.2 Transmission lines operated below 100 kV and transformers
with low voltage terminals connected below 100 kV that are part of the
BES, except Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant. Elements may also
supply generating plant loads.

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1 Facilities, creates a bright line between those Facilities that are applicable
to PRC-023-3 – Transmission Relay Loadability and those Facilities in the proposed PRC-025-1 – Generator Relay Loadability. This is achieved by
excluding Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a
BES generating unit or generating plant while allowing these Elements to also supply generating plant loads. Plant loads may include situations
like pumped storage facilities where the generating plant also serves as a load for pumping.
The above applicability items for Section 4.2 “Circuits” that are subject to the standard were modified to exclude those Elements that connect
the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating
plant. Elements may also supply generating plant loads. The added text reads: “except Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Elements may also supply
generating plant loads” and is found in Sections 4.2.1.1, 4.2.2.1, and 4.2.2.2. This eliminates an overlap with PRC-025-1 and places the
performance for lines and transformers that are used exclusively to export energy directly from a BES generating unit or generating plant to the
network under the proposed PRC-025-1 with the understanding that these Elements may also supply generating plant loads.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

9

Already Approved Standard
PRC-023-2 (Retirement)
R1, Criterion 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.”

Proposed Replacement
PRC-025-1 (New)
New Requirement
R1. Each Generator Owner, Transmission Owner, and Distribution
Provider shall apply settings that are in accordance with PRC-025-1 –
Attachment 1: Relay Settings, on each load-responsive protective relay
while maintaining reliable fault protection. [Violation Risk Factor: High]
[Time Horizon: Long-Term Planning]
*Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation
Criteria, Options 14 through 19. (See standard for details)

Notes: The Transmission Owner and Distribution Provider were added to the Applicability of the proposed PRC-025-1 and excluded Elements
that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or
generating plant. Elements may also supply generating plant loads. Therefore, Requirement R1, Criterion 6 has been removed from the proposed
standard PRC-023-3 because this criterion is now replaced (i.e., superseded) by the proposed PRC-025-1 – Generator Relay Loadability standard,
Requirement R1 and its Attachment 1: Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria, Options 14 through 19.
Applicability concerning generation Facilities is now addressed in the proposed PRC-025-1. Although, Requirement R1, Criterion 6 is not shown in
the proposed PRC-023-3, it remains auditable while each entity assures its compliance with the proposed PRC-025-1 criteria according to the
provided Implementation Plan(s).
PRC-023-2 (Retirement)
R1, Attachment A, exclusion 2.4. “Generator protection relays that are
susceptible to load.”

None.

Notes: This exclusion has been superseded by the proposed PRC-025-1 standard that pertains to these relays. The proposed PRC-023-3 standard
does not include any criteria that are relevant to generator protection relays. The proposed PRC-025-1 standard establishes specific criteria for
generator load-responsive protective relays, and renders this exclusion unnecessary.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 4: August 15, 2013)

10

Implementation Plan

PRC-023-3 – Transmission Relay Loadability
Project 2010-13.2 Phase II Relay Loadability
Requested Approvals

•

PRC-023-3 – Transmission Relay Loadability

Requested Retirements

•

PRC-023-2 – Transmission Relay Loadability

Prerequisite Approvals

•

PRC-025-1 – Generator Relay Loadability*
*A supplemental SAR was approved by the Standards Committee at their January 16-17, 2013 meeting to
authorize the drafting team to make changes to PRC-023-2 to comport with the proposed draft PRC-0251 – Generator Relay Loadability in order to establish a bright line between the applicability of loadresponsive protective relays in the current transmission and the proposed generator relay loadability
standards.

Revisions to Defined Terms in the NERC Glossary

•

None

Background

The generator relay loadability standard drafting team and industry stakeholders raised a concern that there is
no bright line to clearly distinguish which load-responsive protective relays pertain to the existing PRC-023-2 –
Transmission Relay Loadability standard, effective in the United States on July 1, 2012, and the proposed PRC025-1 – Generator Relay Loadability standard. To resolve this concern, the drafting team proposed to modify
the applicability section of PRC-023-2. The standard drafting team clarified, for each functional entity, the
applicability of PRC-023-2 by tying applicability to the terminal the load-responsive protective relay that it is
connected to within the Transmission system.

General Considerations

It is expected that the implementation period for PRC-023-2 will have been achieved, in part, by the time PRC023-3 is adopted by the NERC Board of Trustees and by the time of other approvals by applicable

governmental authorities. The proposed PRC-023-3 Implementation Plan now reflects specific milestone dates
that are known time periods consistent with PRC-023-2.
Applicable Entities

•

Distribution Provider

•

Generator Owner

•

Planning Coordinator

•

Transmission Owner

Effective Date
New Standard

PRC-023-3

First day of the first calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the
first day of the first calendar quarter beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.

Standards for Retirement

PRC-023-2

Midnight of the day immediately prior to the Effective Date of PRC-023-3 –
Transmission Relay Loadability in the particular jurisdiction in which the new
standard is becoming effective, except Requirement R1, Criterion 6 which will
remain in force until the effective date of PRC-025-1.

Implementation Plan for Definitions

No definitions are proposed as a part of this standard.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

2

Implementation Plan for PRC-023-3, Requirements R1 through R6

Each Distribution Provider, Generator Owner, Planning Coordinator, and Transmission Owner applicable to
this standard shall be 100% compliant on the following dates:
Implementation Date
Requirement

Applicability

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on transmission lines operating
at 200 kV and above and transformers
with low voltage terminals connected at
200 kV and above, except as noted
below.

R1

•

•

For supervisory elements as
described in PRC-023-3 - Attachment
A, Section 1.6

For switch-on-to-fault schemes as
described in PRC-023-3 - 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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

The later of July 1,
2014 or first day of the
first calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

3

Implementation Date
Requirement

R1
(continued)

R2 and R3

Applicability

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

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on transmission lines operating
at 200 kV and above and transformers
with low voltage terminals connected at
200 kV and above

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

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 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

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 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

First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

4

Implementation Date
Requirement

R2 and R3
continued

R4

Jurisdictions where
Regulatory Approval is
Required

Jurisdictions where No
Regulatory Approval is
Required

Each Transmission Owner, Generator
Owner, and Distribution Provider with
load-responsive phase protection
systems on 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 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

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 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 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 Board of
Trustees adoption, or
First day of the first
as otherwise made
calendar quarter six
months after applicable effective pursuant to
the laws applicable to
regulatory approvals
such ERO
governmental
authorities

Applicability

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

5

Implementation Date
Requirement

R5

R6
(including
parts 6.1 and
6.2)

Applicability

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

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 Owner,
and Distribution Providers must comply
with Requirements R1 through R5

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 day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Later of January 1,
2014 or the first day of
the first calendar
quarter after applicable
regulatory approvals

First day of the first
calendar quarter after
Board of Trustees
adoption, or as
otherwise made
effective pursuant to
the laws applicable to
such ERO
governmental
authorities

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

6

Revisions or Retirements to Already Approved Standards

The following table identifies the sections of the approved standard that shall be added, retired, or revised when this standard is
implemented. If the drafting team is recommending revisions, those changes are identified by the “Proposed Replacement” column.
Already Approved Standard
PRC-023-2
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

Proposed Replacement
PRC-023-3
4.1. Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection
systems as described in PRC-023-2 3 - Attachment A, applied at the
terminals of the 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-023-3 - Attachment A, applied at the
terminals of the 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 3 - Attachment A, applied at the
terminals of the 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

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1, Functional Entity creates a bright line between those load-responsive
protective relays that are applicable to PRC-023-3 – Transmission Relay Loadability and the proposed PRC-025-1 – Generator Relay Loadability.
This is evident by the minor changes to the Applicability text to distinguish the applicability of the relays by which “terminal” the load-responsive
protective relay is connected to within the Transmission system. Applicability is established by ownership of the load-responsive protective
relays, not the Facilities.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

7

Already Approved Standard

Proposed Replacement

PRC-023-2
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.

PRC-023-3
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above, except
linesElements that connect the GSU transformer(s) to the Transmission
system that are used exclusively to export energy directly from a BES
generating unit or generating plant to the network. Elements may also
supply generating plant loads.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the
Planning Coordinator in accordance with Requirement 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
Requirement 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
Requirement 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 Requirement R6.

4.2.2 Circuits Subject to Requirement R6

4.2.2 Circuits Subject to Requirement R6

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

8

Already Approved Standard

Proposed Replacement

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 below 100 kV and transformers
with low voltage terminals connected below 100 kV that are part of the
BES

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, except lines and transformersElements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to
export energy directly from a BES generating unit or generating plant
to the network. Elements may also supply generating plant loads.
4.2.2.2 Transmission lines operated below 100 kV and transformers
with low voltage terminals connected below 100 kV that are part of the
BES, except lines and transformersElements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to
export energy directly from a BES generating unit or generating plant
to the network. Elements may also supply generating plant loads.

Notes: The change in the proposed PRC-023-3 Applicability, Section 4.1 Facilities, creates a bright line between those Facilities that are applicable
to PRC-023-3 – Transmission Relay Loadability and those Facilities in the proposed PRC-025-1 – Generator Relay Loadability. This is achieved by
excluding Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a
BES generating unit or generating plant while allowing these Elements to also supply generating plant loads. Plant loads may include situations
like pumped storage facilities where the generating plant also serves as a load for pumping.
The above applicability items for Section 4.2 “Circuits” that are subject to the standard were modified to exclude those lines and
transformersElements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a
BES generating unit or generating plant to the network. Elements may also supply generating plant loads. The added text reads: “except lines and
transformersElements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a
BES generating unit or generating plant to the network. Elements may also supply generating plant loads” and is found in Sections 4.2.1.1,
4.2.2.1, and 4.2.2.2. This eliminates an overlap with the proposed changes in PRC-025-1 and places the performance for lines and transformers
that are used exclusively to export energy directly from a BES generating unit or generating plant to the network under the proposed PRC-025-1.
with the understanding that these Elements may also supply generating plant loads.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

9

Already Approved Standard
PRC-023-2 (Retirement)
R1, Criterion 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.”

Proposed Replacement
PRC-025-1 (New)
New Requirement
R1. Each Generator Owner, Transmission Owner, and Distribution
Provider shall apply settings that are in accordance with PRC-025-1 –
Attachment 1: Relay Settings, on each load-responsive protective relay
while maintaining reliable fault protection. [Violation Risk Factor: High]
[Time Horizon: Long-Term Planning]
*Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation
Criteria, Options 14 through 19. (See standard for details)

Notes: The Transmission Owner and Distribution Provider were added to the Applicability of the proposed PRC-025-1 and excluded
linesElements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a Bulk
Electric System (BES) generating unit or generating plant to the network; therefore. Elements may also supply generating plant loads. Therefore,
Requirement R1, Criterion 6 has been removed from the proposed standard PRC-023-3 because this criterion is now replaced (i.e., superseded)
by the proposed PRC-025-1 – Generator Relay Loadability standard, Requirement R1 and its Attachment 1: Attachment 1: Relay Settings, Table 1:
Relay Loadability Evaluation Criteria, Options 14 through 19. Applicability concerning generation Facilities is now addressed in the proposed PRC025-1. Although, Requirement R1, Criterion 6 is not shown in the proposed PRC-023-3, it remains auditable while each entity assures its
compliance with the proposed PRC-025-1 criteria according to the provided Implementation Plan(s).
PRC-023-2 (Retirement)
R1, Attachment A, exclusion 2.4. “Generator protection relays that are
susceptible to load.”

None.

Notes: This exclusion has been superseded by the proposed PRC-025-1 standard that pertains to these relays. The proposed PRC-023-3 standard
does not include any criteria that are relevant to generator protection relays. The proposed PRC-025-1 standard establishes specific criteria for
generator load-responsive protective relays, and renders this exclusion unnecessary.

Implementation Plan (PRC-023-3)
Project 2010-13.2 – Phase II Relay Loadability (Draft 3: June 10, 20134: August 15, 2013)

10

Standards Announcement

Project 2010-13.2 Phase 2 of Relay Loadability: Generation
PRC-023-3
Final Ballot for PRC-023-3 is now open through September 13, 2013
Now Available

A final ballot for PRC-023-3 – Transmission Relay Loadability is now being conducted through 8 p.m.
Eastern on Friday, September 13, 2013.
Background information for this project can be found on the project page.
Instructions
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a
ballot; all ballot pool members may change their previously cast votes. A ballot pool member who
failed to cast a ballot during the last ballot window may cast a ballot in the final ballot window. If a
ballot pool member does not participate in the final ballot, that member’s vote cast in the previous
ballot will be carried over as that member’s vote in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
Next Steps
Voting results for the standard will be posted and announced after the ballot window closes. If
approved, the standard will be submitted to the Board of Trustees for adoption and then filed with
the appropriate regulatory authorities.
Standards Development 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement

Project 2010-13.2 Phase 2 of Relay Loadability: Generation
PRC-023-3
Final Ballot Results
Now Available

A final ballot for PRC-023-3 – Transmission Relay Loadability concluded at 8 p.m. Eastern on Friday,
September 13, 2013.
Voting statistics for the final ballot are listed below, and the Ballot Results page provides a link to the
detailed results. This standard achieved a quorum and sufficient affirmative votes for approval.
Approval
Quorum: 85.93 %
Approval: 90.83 %
Background information for this project can be found on the project page.
Next Steps
Voting results for the standard will be posted and announced after the ballot window closes. The
standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development 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 Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards
Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2010-13.2 PRC-023 Ballot_1 July 2013

Password

Ballot Period: 9/4/2013 - 9/13/2013
Log in

Ballot Type:
Total # Votes: 336

Register

Total Ballot Pool: 391
Quorum: 85.93 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
90.83 %
Vote:
Ballot Results: The standard has passed.

 Home Page
Summary of Ballot Results

Affirmative

Negative

Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote

1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals

1
2
3
4
5
6
7
8
9

108

1

73

0.924

6

0.076

0

9

20

9

0.7

7

0.7

0

0

0

0

2

86

1

60

0.87

9

0.13

0

6

11

29

1

17

0.85

3

0.15

0

4

5

90

1

64

0.842

12

0.158

0

6

8

54

1

41

0.872

6

0.128

0

0

7

1

0

0

0

0

0

0

0

1

4

0.3

3

0.3

0

0

0

0

1

1

0.1

1

0.1

0

0

0

0

0

9

0.9

9

0.9

0

0

0

0

0

391

7

275

6.358

36

0.642

0

25

55

Individual Ballot Pool Results

Ballot
Segment

1
1
1
1
1
1

Organization

Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric

Member

Eric Scott
Paul B Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative

NERC
Notes

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

Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Big Rivers Electric Corp.
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District

James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Chris Bradley
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Chang G Choi

Affirmative

Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Bob Solomon

Affirmative

Ajay Garg
Martin Boisvert
Molly Devine
Tino Zaragoza

Affirmative
Affirmative
Affirmative

Michael Moltane

Affirmative

Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Jennifer Flandermeyer
Stanley T Rzad
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Allan Long
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine

Affirmative
Affirmative

Negative
Affirmative
Abstain
Affirmative

Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Terri Pyle
Doug Peterchuck

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative

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

Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Xcel Energy, Inc.

2

BC Hydro

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

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Alameda Municipal Power
Ameren Services
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
City of Austin dba Austin Energy
City of Farmington
City of Redding
City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
ComEd

1

Jen Fiegel
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
John Shaver
Noman Lee Williams
Howell D Scott
Steven Powell
Tracy Sliman
John Tolo
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Michelle Clements
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Douglas Draeger
Mark Peters
Chris W Bolick
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
Adam M Weber
Thomas C Duffy
Andrew Gallo
Linda R Jacobson
Bill Hughes
Bill R Fowler
Michelle A Corley
Charles Morgan
John Bee

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Affirmative
Affirmative

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative

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
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Peter T Yost
Gerald G Farringer
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Lee Schuster
Danny Lindsey
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
Donald Hargrove
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

NERC Standards
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
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

Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions

Kenneth Goldsmith
Duane S Dahlquist
Reza Ebrahimian

Abstain
Affirmative
Affirmative

Tim Beyrle
Nicholas Zettel
John Allen

Affirmative
Affirmative

Margaret Powell

Affirmative

Tracy Goble
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Mark Ringhausen

Affirmative
Negative
Negative
Affirmative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Steve Wenke
Clement Ma

Affirmative
Affirmative
Affirmative

Mike D Kukla

Affirmative

Francis J. Halpin
Shari Heino
Chifong Thomas
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
Marcus Ellis
Mike Garton
Dale Q Goodwine
Dan Roethemeyer

Negative
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative

Abstain
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative

Dana Showalter
Gustavo Estrada
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Abstain
Affirmative
Affirmative
Affirmative

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
6
6
6
6
6
6
6
6
6
6

Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
PacifiCorp
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Chelan County
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
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.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Utility System Effeciencies, Inc. (USE)
Westar Energy
Western Farmers Electric Coop.
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York

David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando

Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

David Gordon

Affirmative

Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
Bonnie Marino-Blair
Matt E. Jastram
Annette M Bannon
Tim Kucey
John Yale
Steven Grega

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Michiko Sell

Affirmative

Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Erika Doot
Robert L Dintelman
Bryan Taggart
Clem Cassmeyer
Linda Horn
Scott E Johnson
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

Affirmative
Affirmative
Abstain

Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
9
10
10
10
10
10
10
10
10
10

Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alcoa, Inc.

Massachusetts Attorney General
Commonwealth of Massachusetts Department
of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

David J Carlson
Louis S. Slade
Greg Cecil
Luis Rodriguez
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Steve C Hill
Joseph O'Brien
Alan Johnson
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

John J. Ciza

Negative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Affirmative

Peter H Kinney

Affirmative

David Hathaway
David F Lemmons
Thomas Gianneschi
Debra R Warner
Roger C Zaklukiewicz
Edward C Stein
Frederick R Plett

Affirmative
Affirmative

Affirmative

Affirmative
Affirmative
Affirmative

Donald Nelson

Affirmative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Emily Pennel
Donald G Jones
Steven L. Rueckert

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=9895441a-72b2-4399-83f5-5db3682a1227[9/17/2013 11:53:27 AM]

Exhibit E
Unit Auxiliary Transformer (UAT) Relay Loadability Report

Exhibit E—Unit Auxiliary Transformer (UAT) Relay Loadability Report
Background and Objective
Reliability Standard, PRC-025-1 – Generator Relay Loadability (standard), developed under
NERC Project 2010-13.2 – Phase 2 of Relay Loadability: Generation, was adopted by the NERC
Board of Trustees (Board) on August 15, 2013. Subsequent to the standard’s adoption, the Board
asked if a potential reliability gap exists on load-responsive protective relays that are installed on
the low-voltage side of the unit auxiliary transformer (UAT). Only the relays installed on the
high-voltage side of the UAT are applicable to the standard. The request by the Board was in
response to unresolved minority comments made by industry stakeholders arguing that relays on
the low-voltage side of the UAT should be applicable to the standard.
In response to the Board’s question, the standard drafting team conducted a basic study to
investigate whether relays on the low-voltage side of the UAT experience loadability challenges
during the stressed system conditions anticipated by the standard. Additional information
regarding the basis for the standard and its criteria is found in the Guidelines and Technical Basis
section of the standard or on the Project 2010-13.21 project page. The approach of this study was
to develop a model for an actual event that presented a depressed voltage to the plant’s auxiliary
systems and validate that model using recorded data from that event. The study data was used to
determine the expected relay loadability response on the low-voltage side of the UAT under the
stressed system conditions and to determine if the low-voltage side relays are challenged by the
loadability conditions addressed in the standard.
Approach
Using the Electrical Transient Analyzer Program® (ETAP) modeling software, a basic model of
an actual generating plant’s auxiliary system was built and is shown in the Appendix. A
composite model of plant auxiliary equipment (connected load) such as motors, station service
transformers, and variable frequency drives was used because actual event data facilitated fine
tuning of the model to match the actual event. This resulted in composite loads being placed at
four low-voltage side buses to represent the connected load.
Two different low-voltages were used to be representative of a typical generating plant’s
auxiliary systems. The load on both the 7 kV and 4 kV buses were a mixture of impedance type
loads with induction motors. The 7kV bus load was 75-80% induction motors and the 4 kV bus
load was 70-75% induction motor. The simplified bus loads, modeled as composite loads, were
determined to have sufficient accuracy.
A digital fault recorder (DFR) captured an actual event at the plant being modeled where the
balanced three phase voltage was depressed to approximately 85% of the nominal system
voltage, representative of the stressed system conditions. The event lasted for approximately 0.4
seconds with the generating unit(s) remaining on-line during and after the event. The generator
excitation system responded as expected by increasing field voltage to support the automatic
voltage regulator generator voltage setpoint.
1

http://www.nerc.com/pa/Stand/Pages/Project-2010-13-2-Phase-2-Relay-Loadability-Generation.aspx

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Additional analysis was performed using the Siemens PTI PSS®E powerflow and transient
stability analysis software. This additional analysis was used to assess the time-varying nature of
the station service load.
Model Validation
The ETAP plant model was verified using real-time data from the on-site DFR and revenue
meter. Table 1 shows a comparison between the available field data and results from the ETAP
load flow simulation for the normal operating condition. All results were within ±2%; except for
generator gross MVAR (5.9%) which is negligible for this study. The simulation results when
compared to the DFR event data confirm that the model is accurate for this steady state operating
condition and suitable for the study.
Table 1. ETAP Study Model Validation
Generator/Switchyard Values
DFR
Gen kV
19.76
Gen kA
24.37
Switchyard kV (Transmission)
348.53
MW (gross)
827
MVAR (gross)
102
Auxiliaries
DFR
UAT 2-1 High-side kA
Not captured
2A1 kA
1.29
2B1 kA
2.08
UAT 2-2 High-side kA
Not captured
2A2 kA
1.3
2B2 kA, 12B2
2.48

ETAP
19.78
24.3
348.5
827
96
ETAP
0.92
1.28
2.1
1.03
1.3
2.45

ETAP Simulation Results
Two studies were conducted. Study 1 simulated the expected results on the low-voltage side of
the UAT based on the actual event modeled. The low-voltage buses in Study 1 observed current
changes ranging from 6.8% to 10%, versus -1.9% to 8.1% for the actual event as shown in Table
2. Thus the results from Study 1 are conservative and provide additional margin. The percentage
difference in 4kV bus load currents in the study comparing the ETAP values to field results
(10%) are attributed to using a single composite lump load. In order to obtain ETAP values
closer to the field results, a detailed model for motors and impedance loads at each 4kV bus
would be required. Since the information would be difficult to obtain, it is not feasible to perform
the study in the time allowed. The ETAP study also does not consider the effects of field forcing
the AVR would contribute during the time frame of the event.
While the study was performed for one plant auxiliary configuration using approximately a 70%
to 80% inductive load ratio depending on the bus loading, the types of auxiliary load (e.g.,
pumps, fans, compressors, and other impedance loads) are common to all generating units and
generating plants. The primary difference among various types of generating units and plants are
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the quantity and size of the loads. Thus, the percent current increases in response to depressed
voltage are typical values that would be expected for other plant auxiliary configurations.
The results in Table 2 for this particular event (Study 1) indicate there are small changes in
current on the low-voltage side of the UAT. The standard drafting team theorizes that the ratio of
induction motor load to constant impedance load resulted in a low overall increase in current.
During stressed system conditions, induction type loads tend to have an increase current while
impedance type loads tend to have a decrease in current.
Since inductive loads are constant kilovolt ampere (kVA) loads which will increase current in
response to a depressed voltage, a second study (Study 2) was conducted to test the sensitivity of
the Study 1 results. To test the expected range of increased current, Study 2 simulated the lowvoltage side of the UAT by holding the total kVA load constant while increasing the inductive
load ratio to 90% at each bus and is only used in this study to illustrate a relative magnitude
increase in current for the 85% stressed system voltage condition. Using a value higher than 90%
is not practical as all generating unit and plant configurations have some level of constant
impedance loading. Table 3 lists the percent increase in current resulting from the 90% inductive
load ratio. The low-voltage buses in Study 2 observed current changes ranging from 11.0 to
14.4%.

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Table 2. ETAP Study 1 at 85% Transmission Voltage to Event Conditions
Pre
Pre
During During
Generator & Switchyard
(Actual) (ETAP) (Actual) (ETAP)
Gen kV
19.7
19.7
17.29
17.24
Gen kA
20.2
20.17
24.14
23.89
Gen MW (gross)
688
688
688
688
Gen MVAR (gross)
2
15
159
188
Auxiliaries
UAT 2-1 HS kA
2A1 kA (7 kV)
2B1 kA (4 kV)
UAT 2-2 HS kA
2A2 kA (7 kV)
Composite
2B2 , 12B2 (4 kV)

Pre
(Actual)

Pre
(ETAP)

1.23
1.97
1.49
2.14

0.88
1.23
1.95
1.0
1.5
2.12

During
(Actual)
1.3
1.92
1.61
2.1

During
(ETAP)
Study 1
0.94
1.34
2.09
1.09
1.65
2.27

%
Change
(ETAP)
Study 1
6.8
8.9
7.2
9.0
10.0
7.1

%
Change
(Actual)
5.7
-2.4
8.1
-1.9

Table 3. ETAP Study 2 at 85% Transmission Voltage with Higher Inductive UAT Loading
Pre
Pre
During During
Generator & Switchyard
(Actual) (ETAP) (Actual) (ETAP)
Gen kV
19.7
19.7
17.29
17.24
Gen kA
20.2
20.17
24.14
23.89
Gen MW (gross)
688
688
688
688
Gen MVAR (gross)
2
15
159
188

Auxiliaries
UAT 2-1 HS kA
2A1 kA (7 kV)
2B1 kA (4 kV)
UAT 2-2 HS kA
2A2 kA (7 kV)
Composite
2B2 , 12B2 (4 kV)

Pre
(Actual)

Pre
(ETAP)

1.23
1.97
1.49
2.14

0.88
1.23
1.95
1.0
1.5
2.12

Project 2010-13.2 – Phase 2 Relay Loadability: Generation
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During
(Actual)
1.3
1.92
1.61
2.1

During
(ETAP)
Study 2
0.99
1.38
2.23
1.11
1.68
2.39

%
Change
(Actual)
5.7
-2.4
8.1
-1.9

%
Change
(ETAP)
Study 2
12.5
12.2
14.4
11.0
12.0
12.7

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PSS®E Model and Simulation Results
The station service model used in the ETAP analysis was added to a 955 MVA generating unit in
the Eastern Interconnection model. This generating unit is similar in size to the unit modeled in
the ETAP analysis. The unit in the PSS®E model was selected because it was one the units used
in simulations supporting the NERC System Protection and Control Subcommittee (SPCS)
Power Plant and Transmission System Protection Coordination report, which was one of the
reference documents used in development of PRC-025-1. This generating unit also is one for
which recorded data is available from the August 14, 2003 event. This unit is located in western
Michigan and responded to a depressed transmission system voltage until the local transmission
voltage recovered after the east-west system separation occurred.
The model was modified to account for a difference in generator terminal voltage by adjusting
the UAT turns ratio. The PSS®E complex load model (CLOD) was used to represent the station
service load using the same percentages of large motor load and constant impedance load as the
ETAP Study 1 (75-80% for the 7 kV buses and 70-75% for the 4 kV buses).
The simulation is based on the “synchronous generator simulation criteria” described in the
Guidelines and Technical Basis of PRC-025-1. In this method a reactor is switched on the highvoltage side of the generator step-up (GSU) transformer to lower the transmission system voltage
to 0.85 per unit prior to response of the generator excitation system. In these simulations the
maximum load current on the UAT occurs when the station service load responds to the initial
voltage drop. The load current is reduced as the generator increases its reactive output to support
its terminal voltage. A maximum excitation limiter (MEL) was modeled in the simulation. As the
MEL reduces the reactive output of the generator, the generator and station service voltage
decrease. As a result, the load current increases and settles at a level higher than the pre-event
current, but lower than the maximum observed current. For the conditions modeled in this
simulation, the MEL reduced the reactive output approximately 15 seconds after the initial event.
MEL parameters vary among generating units. However, variations in these parameters are not
expected to affect the maximum current or the final current. This is because the MEL is set to
allow full field-forcing for a period of time within the generator short-time capability, and to
reduce the reactive output to a final value with the generator steady-state capability.
The results for the simulation are presented in Table 4. The pre-event and maximum currents are
similar to the results obtained in the ETAP analysis. Differences in current on the high-voltage
side of the UAT are a result of the different generator terminal voltages. The table lists the preevent and maximum load current on each bus, and also lists the current at four discrete times (1
s, 5 s, 10 s, and 20 s) after the initial event. The maximum current is observed approximately 0.4
s after the initial event. The current is listed in kA in the top half of the table and as a percentage
difference from the pre-event current in the bottom half. The simulation demonstrates that the
maximum load current is in the range from 4.8 to 10.0% higher than the pre-event load current.
The load current begins to drop from the maximum value within 1 s of the initial event. The final
current after MEL operation is in the range from 2.2 to 5.4% higher than the pre-event current.

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Table 4. PSS®E Study 1 at 85% Transmission Voltage with Original UAT Loading
PreAuxiliaries
Max
1s
5s
10 s
20 s
Event
UAT 2-1 HS kA
0.805
0.874
0.846
0.818
0.817
0.831
2A1 kA (7 kV)
1.256
1.349
1.326
1.279
1.276
1.305
2B1 kA (4 kV)
2.016
2.120
2.093
2.038
2.034
2.066
UAT 2-2 HS kA
0.918
1.006
0.972
0.936
0.932
0.957
2A2 kA (7 kV)
1.523
1.675
1.638
1.562
1.555
1.606
Composite 2B2 , 12B2 (4
2.179
2.283
2.256
2.199
2.195
2.228
kV)
Auxiliaries
UAT 2-1 HS kA
2A1 kA (7 kV)
2B1 kA (4 kV)
UAT 2-2 HS kA
2A2 kA (7 kV)
Composite 2B2 , 12B2 (4
kV)

% Max

%1s

%5s

% 10 s

% 20 s

8.3
7.6
5.3
9.6
10.0
4.8

4.8
5.7
3.8
5.9
7.6
3.5

1.6
1.8
1.1
2.0
2.6
0.9

1.5
1.6
0.9
1.5
2.1
0.7

3.1
3.9
2.5
4.2
5.4
2.2

Similar to the ETAP analysis, a second simulation was run using 90% large motor load on each
bus. As expected, these simulations resulted in high loader current than Study 1. Results for the
second simulation are presented in Table 5. In the second study the maximum current on each
load bus is in the range from 9.6 to 13.4% above the pre-event current and the final current is in
the range from 5.1 to 7.4% above the pre-event current.

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Table 5. ETAP Study 2 at 85% Transmission Voltage with Higher Inductive UAT
Loading
PreAuxiliaries
Max
1s
5s
10 s
20 s
Event
UAT 2-1 HS kA
0.798
0.909
0.871
0.823
0.819
0.849
2A1 kA (7 kV)
1.240
1.396
1.358
1.282
1.274
1.328
2B1 kA (4 kV)
2.054
2.266
2.210
2.106
2.096
2.167
UAT 2-2 HS kA
0.913
1.042
0.999
0.942
0.935
0.975
2A2 kA (7 kV)
1.518
1.722
1.672
1.571
1.561
1.631
Composite 2B2 , 12B2 (4
2.230
2.445
2.392
2.282
2.275
2.344
kV)
Auxiliaries
UAT 2-1 HS kA
2A1 kA (7 kV)
2B1 kA (4 kV)
UAT 2-2 HS kA
2A2 kA (7 kV)
Composite 2B2 , 12B2 (4
kV)

% Max

%1s

%5s

13.9
12.6
10.3
14.1
13.4
9.6

9.1
9.5
7.6
9.4
10.1
7.3

3.1
3.4
2.5
3.2
3.5
2.3

% 10 s % 20 s
3.6
2.7
2.0
2.4
2.8
2.0

6.4
7.1
5.5
6.8
7.4
5.1

During the event modeled in ETAP, the actual plant output was lower than reported full load
output; therefore, increases in UAT loading would occur at reported full load. A sensitivity
analysis was performed in PSS®E to model higher station service load. In this assessment the
load was increased proportionally until the load on one of the UAT windings was equal to the
winding rating – an increase of approximately 34% on UAT2-1 and 10% on UAT2-2. In these
cases the load current is proportionately higher; however, the observed increases in current are
not significantly different. The base model with 70-80 % motor load exhibited load current
increases in the range from 5.1 to 10.0% (compared to 4.8 to 10.0%) and the higher inductive
load model with 90% motor load exhibited load current increases in the range from 10.1 to
13.6% (compared to 9.6 to 13.4%).Thus, if the actual plant had been at full load, the expected
incremental increases in UAT loading during such an event would be of the same magnitude as
for the actual event modeled.
Analysis of NERC GADS Data
The NERC Generating Availability Data System (GADS) contains outage data for generating
stations across North America. Outages were analyzed for UATs and other station service
transformers with primary winding voltage of 4.16 kV and 480 V. This analysis included 217
UAT outages, 28 outages of 4.16 kV transformers, and 49 outages of 480 V transformers. The
cause codes do not provide adequate granularity to determine why the transformers tripped;
however, approximately 85% of the outage entries included descriptive comments. The majority
of UAT outages with descriptions were scheduled, approximately one-half of the 4.16 kV
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transformer outages were scheduled and one-half forced, and the majority of 480 V transformer
outages were forced.
The descriptions for the forced outages include issues such as transformer failure, overheated
transformer or associated equipment, auxiliary power transfer problems, breaker failure, failure
of equipment supplied by the transformer (e.g., induced draft fan), problems with transformer
outlet leads, current transformer ground, and differential relay operation. Four event descriptions
identify improper or incorrect relay settings – one event on a 480 V transformer was for a ground
fault for which PRC-025-1 would not be applicable; three events on a 4.16 kV transformer
appear to be related to the same relay setting with no other information. While not definitive,
there is nothing in the GADS data to suggest that any generating unit outages occurred due to
UAT or other station service transformer relay loadability issues during a depressed voltage
condition.
Conclusion
Many of the plant auxiliaries (e.g., 4 kV and 7 kV) have a ±10% voltage operating range with
most operating above the nominal; such an operating range allows for increased current during
lower voltages. Industry practice is to set plant auxiliary relays on the low-voltage side of the
UAT to account for a depressed voltage according to equipment ratings. These relays are
generally set with a 10 to 15% margin above the expected lower voltage range of the equipment
rating. Relays on the low-voltage side of the UAT are also set to account for the starting of large
plant auxiliary motors which depresses voltage. The margin in the relay settings accounts for
measuring inaccuracy in current transformers and relays, and other uncertainties associated with
the equipment and operating conditions.
The maximum current deviations observed in these simulations would be under or marginally
above the current threshold (pickup setting) at which the relays on the low-voltage side of the
UAT would begin to operate. These relays operate with an inverse-time characteristic such that
an overcurrent condition marginally above the pick-up setting must persist for several seconds
before the relay will assert a trip output. In these simulations the maximum motor load duration
is short in comparison to the operating time of the relay when current is marginally above
pickup, and the load current settles to a value below the pickup setting allowing the relay to
reset.
Based on a comparison of the simulation models and the actual event data, the simulation results
are conservative. The model results, coupled with the GADS analysis, are indicative that a
reliability gap does not result from excluding relays on the low-voltage side of the UAT from
PRC-025-1. However, industry practice may vary and the conservatism in the model does not
fully offset the potential inaccuracies and uncertainties in the relay setting. Thus, while indicative
that a reliability gap does not result, this analysis is not definitive.
Recommendation
The study using both DFR event data and simulation, and the GADS data analysis, revealed
there is not a material gap in reliability; therefore, the recommendation is not to include the lowvoltage side relays in the PRC-025-1 standard.
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Furthermore, the standard drafting team recognizes that the goal of PRC-025-1 is to prevent the
unnecessary tripping of generators during a system disturbance for conditions that do not pose a
risk of damage to the associated equipment. Since the study revealed that increased loading of
the low-side UAT protective relays may reach margins generally employed by industry, other
preemptive steps may be desirable. If so, the standard drafting team recommends to NERC a
tiered approach to further address this risk.
1. Monitoring – Investigate the feasibility to revise or append the NERC GADS cause codes
with greater granularity to facilitate the monitoring and tracking of the UAT, for both
load-responsive high-side and low-side protective relay(s) that cause the loss of
generation due to a depressed voltage as anticipated by the PRC-025-1 standard.
2. Guideline – Solicit industry input through the appropriate NERC committee for
establishing a guideline for setting load-responsive UAT low-side overload protective
relays to account for increased loading during depressed voltages. This guideline should
be based on information revealed through monitoring that demonstrates a need for
industry guidance and not a reliability standard. This option is next if monitoring is not
feasible.
3. Standard – Revise the PRC-025-1 standard or create a new standard to address the
loadability of the load-responsive UAT high-side and low-side protective relays if lessons
learned through monitoring and/or developed guidance do not demonstrate the necessary
reliability described in the standard.

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Appendix

Unit Data
955 MVA/893 MV
20 kV

20 kV Iso-phase Bus 2

UAT 2-2
40/20/20 MVA
19/6.9/4.16
12.09/24.34/43.71 % Z

UAT 2-1
40/20/20 MVA
19/6.9/4.16
12.09/24.34/43.71 % Z

7 kV

4 kV

51 DFR

Bus 2A1

Load 2A1
14.95 MVA

7 kV

51 DFR

51 DFR

Bus 2B1

4 kV

Bus 2A2

Load 2A1
14.00 MVA

Load 2A1
18.18 MVA

51 DFR

Bus 2B2

Load 2A1
13.30 MVA

51 DFR

Bus 12B1

Load 2A1
1.43 MVA

CB1

MPT2
800 MVA
19.5/345 kV
10.6 % Z

Plant Switchyard 345 kV

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