Prc-23-6

PRC-023-6 – Transmission Relay Loadability

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

None.

A. Introduction
1. Title:

Transmission Relay Loadability

2. Number:

PRC-023-6

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
describedin PRC-023-6 - 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-023-6 - 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-023-6 - 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

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.
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PRC-023-6 – Transmission Relay Loadability

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
accordancewith 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
withlow voltage terminals connected at 100 kV to 200 kV, except
Elements that connect the GSU transformer(s) to the Transmission
system that areused 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.

5. Effective Dates: See Implementation Plan. As provided therein, each Generator Owner,
Transmission Owner, and Distribution Provider that owns circuits that become applicable
to this standard pursuant to Requirement R6 shall become compliant with R1 through R5
on the later of the first day of the first calendar quarter 39 months following notification
by the Planning Coordinator of a circuit’s inclusion on a list of circuits 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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PRC-023-6 – Transmission Relay Loadability

B. Requirements and Measures
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
1
seasonal 15-minute Facility Rating 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 greaterof:
•

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 lineinductive 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. Reserved.
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.
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.

1

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PRC-023-6 – 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
2
duration that exceeds the transformer’s mechanical withstand capability .

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 minutesto 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
3
no lessthan 140° C for the winding hot spot temperature .

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
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.
2

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PRC-023-6 – Transmission Relay Loadability

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.
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)
R2. Reserved.
M2. Reserved.
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]
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)
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]
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)
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
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PRC-023-6 – Transmission Relay Loadability

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]
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)
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-0236, 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-023-6 per application of Attachment B,
including identification of the first calendar year in which any criterion in PRC-0236, 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.
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-023-6,
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)

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PRC-023-6 – Transmission Relay Loadability

C. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an Applicable
Governmental Authority, in their respective roles of monitoring and/or enforcing
compliance with mandatory and enforceable Reliability Standards in their
respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the period
of time an entity is required to retain specific evidence to demonstrate compliance.
For instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask an
entity to provide other evidence to show that it was compliant for the full-time
period since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The 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 noncompliance 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 Enforcement Program: As defined in the NERC Rules of
Procedure, “Compliance Monitoring and Enforcement Program” refers to the
identification of the processes that will be used to evaluate data or information for
the purpose of assessing performance or outcomes with the associated Reliability
Standard.

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PRC-023-6 – Transmission Relay Loadability

Violation Severity Levels
Violation Severity Levels

R#
R1

Lower VSL
N/A

Moderate VSL
N/A

High VSL
N/A

Severe VSL
The responsible entity did not
use any one of the following
criteria (Requirement R1
criterion 1 through 13) for any
specific circuit terminal to
prevent its phase protective
relay settings from limiting
transmission system
loadability while maintaining
reliable protection of the 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

N/A

N/A

N/A

Reserved.

R3

N/A

N/A

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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PRC-023-6 – Transmission Relay Loadability
Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

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

R4

N/A

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.

R5

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

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PRC-023-6 – Transmission Relay Loadability
Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
each calendar year, with no
more than 15 months
between reports.

R6

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 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

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 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,

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

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PRC-023-6 – Transmission Relay Loadability

R#

Violation Severity Levels
Lower VSL

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

High VSL
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 VSL
within Attachment B at least
once each calendar year,
with no more than 15
months between
assessments to determine
the circuits in its Planning
Coordinator area for which
applicable entities must
comply with the standard but
failed to maintain the list of
circuits determined
according to the process
described in Requirement R6.
(part 6.1)
OR
The Planning Coordinator
used the criteria established
within Attachment B at least
once each calendar year,
with no more than 15
months between
assessments to determine
the circuits in its Planning
Coordinator area for which
applicable entities must
comply with the standard
and met 6.1 but failed to
provide the list of circuits to
the Reliability Coordinators,
Transmission Owners,
Generator Owners, and
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PRC-023-6 – Transmission Relay Loadability

R#

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL
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.

D. Regional Variances
None.

E. Associated Documents

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
NERC Reliability Standard PRC-023-6 Implementation Plan.
NERC Reliability Standard PRC-023-6 Technical Rationale.
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PRC-023-6 – Transmission Relay Loadability

Version History
Version

Date

Change
Tracking

Action

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

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

Revision

2

Filed for
approval April
19, 2010
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.

4

November 13,
2014

Adopted by the NERC Board of Trustees

Replaced
references to
Special Protection
System and SPS
with Remedial
Action Scheme and
RAS

4

November 19,
2015

FERC Order issued approving PRC-023-4.
Docket No. RM15-13-000.

5

May 13, 2021

Adopted by the NERC Board of Trustees

6

March 4, 2022

FERC Order issued approving PRC-023-5

7

February 16,2022 Adopted by NERC Board of Trustees
PRC-023-6.

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PRC-023-6 – Transmission Relay Loadability
7

January 24, 2024 FERC issued a delegated letter order
approving PRC-023-6. Docket No. RD23-5000

7

February 2, 2024 Effective Date

April 1, 2024

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PRC-023-6 – Transmission Relay Loadability

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
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.
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. Reserved.
2.4. Reserved.
2.5. Relay elements used only for Remedial Action Schemes 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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PRC-023-6 – Transmission Relay Loadability

Attachment B
Circuits to Evaluate
•

Transmission lines operated at 100 kV to 200kV and transformers with low voltage
terminals connected at 100 kV to 200 kV.

•

Transmission lines operated below 100 kV and transformers with low voltageterminals
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 selected by the Planning Coordinator or Transmission Planner based on
Planning Assessments of the Near-Term Transmission Planning Horizon that identify
instances of instability, Cascading, or uncontrolled separation, that adversely impact the
reliability of the Bulk Electric System for planning events.
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.
4

B4. The circuit is identified through the following sequence of power flow analyses 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.
i.
4

If the Facility Rating is based on a loading duration of up to and including four

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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PRC-023-6 – Transmission Relay Loadability

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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