Prc-004-6

PRC-004-6 — Protection System Misoperation Identification and Correction

A. Introduction
1.

Title:

Protection System Misoperation Identification and Correction

2.

Number:

PRC-004-6

3.

Purpose:

Identify and correct the causes of Misoperations of Protection
Systems for Bulk Electric System (BES) Elements.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Transmission Owner
4.1.2 Generator Owner
4.1.3 Distribution Provider
4.2. Facilities:
4.2.1 Protection Systems for BES Elements, with the following exclusions:
4.2.1.1 Non-protective functions that are embedded within a Protection
System.
4.2.1.2 Protective functions intended to operate as a control function
during switching. 1
4.2.1.3 Special Protection Systems (SPS).
4.2.1.4 Remedial Action Schemes (RAS).
4.2.1.5 Protection Systems of individual dispersed power producing
resources identified under Inclusion I4 of the BES definition
where the Misoperations affected an aggregate nameplate
rating of less than or equal to 75 MVA of BES Facilities.
4.2.2 Underfrequency load shedding (UFLS) that is intended to trip one or
more BES Elements.
4.2.3 Undervoltage load shedding (UVLS) that is intended to trip one or more
BES Elements.

5.

Effective Date: See Implementation Plan.

For additional information and examples, see the “Non-Protective Functions” and “Control Functions” sections in the
Application Guidelines.

1

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PRC-004-6 — Protection System Misoperation Identification and Correction

B. Requirements and Measures
R1. Each Transmission Owner, Generator Owner, and Distribution Provider that owns a
BES interrupting device that operated under the circumstances in Parts 1.1 through
1.3 shall, within 120 calendar days of the BES interrupting device operation, identify
whether its Protection System component(s) caused a Misoperation: [Violation Risk
Factor: High][Time Horizon: Operations Assessment, Operations Planning]
1.1

The BES interrupting device operation was caused by a Protection System or by
manual intervention in response to a Protection System failure to operate; and

1.2

The BES interrupting device owner owns all or part of the Composite Protection
System; and

1.3 The BES interrupting device owner identified that its Protection System
component(s) caused the BES interrupting device(s) operation or was caused by
manual intervention in response to its Protection System failure to operate.
M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it identified the Misoperation of its Protection
System component(s), if any, that meet the circumstances in Requirement R1, Parts
1.1, 1.2, and 1.3 within the allotted time period. Acceptable evidence for Requirement
R1, including Parts 1.1, 1.2, and 1.3 may include, but is not limited to the following
dated documentation (electronic or hardcopy format): reports, databases,
spreadsheets, emails, facsimiles, lists, logs, records, declarations, analyses of sequence
of events, relay targets, Disturbance Monitoring Equipment (DME) records, test
results, or transmittals.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that owns a
BES interrupting device that operated shall, within 120 calendar days of the BES
interrupting device operation, provide notification as described in Parts 2.1 and 2.2.
[Violation Risk Factor: High][Time Horizon: Operations Assessment, Operations
Planning]
2.1 For a BES interrupting device operation by a Composite Protection System or by
manual intervention in response to a Protection System failure to operate,
notification of the operation shall be provided to the other owner(s) that share
Misoperation identification responsibility for the Composite Protection System
under the following circumstances:
2.1.1 The BES interrupting device owner shares the Composite Protection
System ownership with any other owner; and
2.1.2 The BES interrupting device owner has determined that a Misoperation
occurred or cannot rule out a Misoperation; and
2.1.3 The BES interrupting device owner has determined that its Protection
System component(s) did not cause the BES interrupting device(s)
operation or cannot determine whether its Protection System
components caused the BES interrupting device(s) operation.
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PRC-004-6 — Protection System Misoperation Identification and Correction

2.2 For a BES interrupting device operation by a Protection System component
intended to operate as backup protection for a condition on another entity’s BES
Element, notification of the operation shall be provided to the other Protection
System owner(s) for which that backup protection was provided.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates notification to the other owner(s), within the
allotted time period for either Requirement R2, Part 2.1, including subparts 2.1.1,
2.1.2, and 2.1.3 and Requirement R2, Part 2.2. Acceptable evidence for Requirement
R2, including Parts 2.1 and 2.2 may include, but is not limited to the following dated
documentation (electronic or hardcopy format): emails, facsimiles, or transmittals.
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that receives
notification, pursuant to Requirement R2 shall, within the later of 60 calendar days of
notification or 120 calendar days of the BES interrupting device(s) operation, identify
whether its Protection System component(s) caused a Misoperation. [Violation Risk
Factor: High][Time Horizon: Operations Assessment, Operations Planning]
M3. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it identified whether its Protection System
component(s) caused a Misoperation within the allotted time period. Acceptable
evidence for Requirement R3 may include, but is not limited to the following dated
documentation (electronic or hardcopy format): reports, databases, spreadsheets,
emails, facsimiles, lists, logs, records, declarations, analyses of sequence of events,
relay targets, DME records, test results, or transmittals.
R4. Reserved.
M4. Reserved.
R5. Each Transmission Owner, Generator Owner, and Distribution Provider that owns the
Protection System component(s) that caused the Misoperation shall, within 60
calendar days of first identifying a cause of the Misoperation: [Violation Risk Factor:
High] [Time Horizon: Operations Planning, Long-Term Planning]
•

Develop a Corrective Action Plan (CAP) for the identified Protection System
component(s), and an evaluation of the CAP’s applicability to the entity’s other
Protection Systems including other locations; or

•

Explain in a declaration why corrective actions are beyond the entity’s control or
would not improve BES reliability, and that no further corrective actions will be
taken.

M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it developed a CAP and an evaluation of the CAP’s
applicability to other Protection Systems and locations, or a declaration in accordance
with Requirement R5. Acceptable evidence for Requirement R5 may include, but is not
limited to the following dated documentation (electronic or hardcopy format): CAP
and evaluation, or declaration.
R6. Each Transmission Owner, Generator Owner, and Distribution Provider shall
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PRC-004-6 — Protection System Misoperation Identification and Correction

implement each CAP developed in Requirement R5, and update each CAP if actions or
timetables change, until completed. [Violation Risk Factor: High][Time Horizon:
Operations Planning, Long-Term Planning]
M6. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it implemented each CAP, including updating
actions or timetables. Acceptable evidence for Requirement R6 may include, but is not
limited to the following dated documentation (electronic or hardcopy format): records
that document the implementation of each CAP and the completion of actions for
each CAP including revision history of each CAP. Evidence may also include work
management program records, work orders, and maintenance records.

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PRC-004-6 — Protection System Misoperation Identification and Correction

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall keep
data or evidence to show compliance as identified below unless directed by its
CEA to retain specific evidence for a longer period of time as part of an
investigation.
•

The Transmission Owner, Generator Owner, and Distribution Provider shall
retain evidence of Requirements R1, R2, and R3, Measures M1, M2, and M3
for a minimum of 12 calendar months following the completion of each
Requirement.

•

The Transmission Owner, Generator Owner, and Distribution Provider shall
retain evidence of Requirement R5, Measure M5, including any supporting
analysis per Requirements R1, R2, and R3, for a minimum of 12 calendar
months following completion of each CAP, completion of each evaluation,
and completion of each declaration.

•

The Transmission Owner, Generator Owner, and Distribution Provider shall
retain evidence of Requirement R6, Measure M6 for a minimum of 12
calendar months following completion of each CAP.

If a Transmission Owner, Generator Owner, or Distribution Provider is found
non-compliant, it shall keep information related to the non-compliance until
mitigation is complete and approved, or for the time specified above, whichever
is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

•

Spot Checking
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PRC-004-6 — Protection System Misoperation Identification and Correction

•

Compliance Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
None.

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PRC-004-6 — Protection System Misoperation Identification and Correction

Violation Severity Levels
R#

R1.

Time
Horizon

VRF

Operations High
Assessment,
Operations
Planning

Violation Severity Levels

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 120
calendar days and less
than or equal to 150
calendar days of the
BES interrupting
device operation.

The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 150
calendar days and less
than or equal to 165
calendar days of the
BES interrupting
device operation.

The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 165
calendar days and less
than or equal to 180
calendar days of the
BES interrupting
device operation.

The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 180
calendar days of the
BES interrupting
device operation.
OR
The responsible entity
failed to identify
whether its Protection
System component(s)
caused a
Misoperation in
accordance with
Requirement R1.

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PRC-004-6 — Protection System Misoperation Identification and Correction

R#

R2.

Time
Horizon

VRF

Operations High
Assessment,
Operations
Planning

Violation Severity Levels

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 120
calendar days and less
than or equal to 150
calendar days of the
BES interrupting
device operation.

The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 150
calendar days and less
than or equal to 165
calendar days of the
BES interrupting
device operation.

The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 165
calendar days and less
than or equal to 180
calendar days of the
BES interrupting
device operation.

The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 180
calendar days of the
BES interrupting
device operation.
OR
The responsible entity
failed to notify one or
more of the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2.

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PRC-004-6 — Protection System Misoperation Identification and Correction

R#

R3.

Time
Horizon

VRF

Operations High
Assessment,
Operations
Planning

Violation Severity Levels

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
identified whether or
not its Protection
System component(s)
caused a
Misoperation in
accordance with
Requirement R3, but
was less than or equal
to 30 calendar days
late.

The responsible entity
identified whether or
not its Protection
System component(s)
caused a
Misoperation in
accordance with
Requirement R3, but
was greater than 30
calendar days and less
than or equal to 45
calendar days late.

The responsible entity
identified whether or
not its Protection
System component(s)
caused a
Misoperation in
accordance with
Requirement R3, but
was greater than 45
calendar days and less
than or equal to 60
calendar days late.

The responsible entity
identified whether or
not its Protection
System component(s)
caused a
Misoperation in
accordance with
Requirement R3, but
was greater than 60
calendar days late.
OR
The responsible entity
failed to identify
whether or not a
Misoperation of its
Protection System
component(s)
occurred in
accordance with
Requirement R3.

R4.
Reserved.

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PRC-004-6 — Protection System Misoperation Identification and Correction

R#

R5.

Time
Horizon

Operations
Planning,
Long-Term
Planning

Violation Severity Levels

VRF

High

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 60
calendar days and less
than or equal to 70
calendar days of first
identifying a cause of
the Misoperation.

The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 70
calendar days and less
than or equal to 80
calendar days of first
identifying a cause of
the Misoperation.

The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 80
calendar days and less
than or equal to 90
calendar days of first
identifying a cause of
the Misoperation.

The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 90
calendar days of first
identifying a cause of
the Misoperation.

OR

OR

OR

(See next page)

(See next page)

(See next page)

OR
The responsible entity
failed to develop a
CAP or explain in a
declaration in
accordance with
Requirement R5.
OR

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PRC-004-6 — Protection System Misoperation Identification and Correction

R#

R6.

Time
Horizon

Operations
Planning,
Long-Term
Planning

VRF

High

Violation Severity Levels

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 60
calendar days and less
than or equal to 70
calendar days of first
identifying a cause of
the Misoperation.

The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 70
calendar days and less
than or equal to 80
calendar days of first
identifying a cause of
the Misoperation.

The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 80
calendar days and less
than or equal to 90
calendar days of first
identifying a cause of
the Misoperation.

The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 90
calendar days of first
identifying a cause of
the Misoperation.

N/A

The responsible entity
failed to implement a
CAP in accordance
with Requirement R6.

The responsible entity N/A
implemented, but
failed to update a
CAP, when actions or
timetables changed,
in accordance with
Requirement R6.

OR
The responsible entity
failed to develop an
evaluation in
accordance with
Requirement R5.

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PRC-004-6 — Protection System Misoperation Identification and Correction

D. Regional Variances
None.
E. Associated Documents
NERC System Protection and Controls Subcommittee of the NERC Planning Committee,
Assessment of Standards: PRC-003-1 – Regional Procedure for Analysis of Misoperations of
Transmission and Generation Protection Systems, PRC-004-1 – Analysis and Mitigation of
Transmission and Generation Protection Misoperations, PRC-016-1 – Special Protection
System Misoperations, May 22, 2009. 2

Version History
Versio
n

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

December 1, 2005

1. Changed incorrect use of
certain hyphens (-) to “en
dash” (–) and “em dash (—).”

01/20/06

2. Added “periods” to items
where appropriate.
3. Changed “Timeframe” to
“Time Frame” in item D, 1.2.
1a

February 17, 2011

Adopted by NERC Board of
Trustees

Project 2009-17
interpretation adding
Appendix 1 - Interpretation
regarding applicability of
standard to protection of
radially connected
transformers

1a

September 26,
2011

Appended FERC-approved
interpretation of R1 and R3 to
version 1

FERC’s Order approving the
interpretation of R1 and R3 is
effective as of September 26,
2011

2

August 5, 2010

Adopted by NERC Board of
Trustees

Project 2010-12 modifications
to address Order No. 693
Directives contained in
paragraph 1469

(http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%20DL/PRC-003-004016%20Report.pdf).
2

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PRC-004-6 — Protection System Misoperation Identification and Correction

Versio
n

2a

Date

Action

Change Tracking

September 26,
2011

Appended FERC-approved
interpretation of R1 and R3 to
version 2

FERC’s Order approving the
interpretation of R1 and R3 is
effective as of September 26,
2011

2.1a

February 9, 2012

Adopted by NERC Board of
Trustees

Errata change under Project
2010-07 to add “…and
generator interconnection
Facility…”

3

August 14, 2014

Adopted by NERC Board of
Trustees

Revision under Project 201005.1

4

November 13,
2014

Adopted by NERC Board of
Trustees

Applicability revision under
Project 2014-01 to clarify
application of Requirements
to BES dispersed power
producing resources

5

May 7, 2015

Adopted by NERC Board of
Trustees

Revision under Project 200802.2

5(i)

June 22, 2015

Adopted by NERC Board of
Trustees

Revision to VRF designations
from “Medium” to “High” for
Requirements R1 through R6,
in compliance with the
Federal Energy Regulatory
Commission’s directive in N.
Am. Elec. Reliability Corp.,
151 FERC ¶ 61,129 (2015)

6

May 9, 2019

Adopted by the NERC Board of
Trustees

R4 retired under Project
2018-03 Standards Efficiency
Review Retirements.

6

September 17, 2020

FERC Order issued approving
PRC-004-6. Docket No.
RM19-16-000, RM19-17-000

6

December
14,2020

6

April 1, 2021

FERC Approval
Effective Date

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PRC-004-6 Supplemental Material

Guidelines and Technical Basis
Introduction

This standard addresses the reliability issues identified in the letter 3 from Gerry Cauley, NERC
President and CEO, dated January 7, 2011.
“Nearly all major system failures, excluding perhaps those caused by severe weather,
have misoperations of relays or automatic controls as a factor contributing to the
propagation of the failure. …Relays can misoperate, either operate when not needed or
fail to operate when needed, for a number of reasons. First, the device could experience
an internal failure – but this is rare. Most commonly, relays fail to operate correctly due
to incorrect settings, improper coordination (of timing and set points) with other
devices, ineffective maintenance and testing, or failure of communications channels or
power supplies. Preventable errors can be introduced by field personnel and their
supervisors or more programmatically by the organization.”
The standard also addresses the findings in the 2011 Risk Assessment of Reliability Performance 4;
July 2011.
“…a number of multiple outage events were initiated by protection system
Misoperations. These events, which go beyond their design expectations and operating
procedures, represent a tangible threat to reliability. A deeper review of the root causes
of dependent and common mode events, which include three or more automatic
outages, is a high priority for NERC and the industry.”
The State of Reliability 2014 5 report continued to identify Protection System Misoperations as a
significant contributor to automatic transmission outage severity. The report recommended
completion of the development of PRC-004-3 as part of the solution to address Protection
System Misoperations.
Definitions

The Misoperation definition is based on the IEEE/PSRC Working Group I3 “Transmission
Protective Relay System Performance Measuring Methodology 6.” Misoperations of a Protection
System include failure to operate, slowness in operating, or operating when not required either
during a Fault or non-Fault condition.
For reference, a “Protection System” is defined in the Glossary of Terms Used in NERC Reliability
Standards (“NERC Glossary”) as:

(http://www.nerc.com/pa/Stand/Project%20201005%20Protection%20System%20Misoperations%20DL/20110209130708Cauley%20letter.pdf).
4 “2011 Risk Assessment of Reliability Performance.” NERC. (http://www.nerc.com/files/2011_RARPR_FINAL.pdf. July 2011). Pg.
3.
5 “State of Reliability 2014.” NERC. (http://www.nerc.com/pa/Stand/Pages/RelaibilityCoordinationProject20066.aspx). May
2014. Pg. 18 of 106.
6 “Transmission Protective Relay System Performance Measuring Methodology.” Working Group I3 of Power System Relaying
Committee of IEEE Power Engineering Society. 1999.
3

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PRC-004-6 Supplemental Material

•

Protective relays which respond to electrical quantities,

•

Communications systems necessary for correct operation of protective functions,

•

Voltage and current sensing devices providing inputs to protective relays,

•

Station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and

•

Control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.

A BES interrupting device is a BES Element, typically a circuit breaker or circuit switcher that has
the capability to interrupt fault current. Although BES interrupting device mechanisms are not
part of a Protection System, the standard uses the operation of a BES interrupting device by a
Protection System to initiate the review for Misoperation.
The following two definitions are being proposed for inclusion in the NERC Glossary:
Composite Protection System – The total complement of Protection System(s) that function
collectively to protect an Element. Backup protection provided by a different Element’s
Protection System(s) is excluded.
The Composite Protection System definition is based on the principle that an Element’s multiple
layers of protection are intended to function collectively. This definition has been introduced in
this standard and incorporated into the proposed definition of Misoperation to clarify that the
overall performance of an Element’s total complement of protection should be considered
while evaluating an operation.
Composite Protection System – Line Example
The Composite Protection System of the Alpha-Beta line (Circuit #123) is comprised of current
differential, permissive overreaching transfer trip (POTT), step distance (classic zone 1, zone 2,
and zone 3), instantaneous-overcurrent, time-overcurrent, out-of-step, and overvoltage
protection. The protection is housed at the Alpha and Beta substations, and includes the
associated relays, communications systems, voltage and current sensing devices, DC supplies,
and control circuitry.
Composite Protection System – Transformer Example
The Composite Protection System of the Alpha transformer (#2) is comprised of internal
differential, overall differential, instantaneous-overcurrent, and time-overcurrent protection.
The protection is housed at the Alpha substation, and includes the associated relays, voltage
and current sensing devices, DC supplies, and control circuitry.
Composite Protection System – Generator Example
The Composite Protection System of the Beta generator (#3) is comprised of generator
differential, overall differential, overcurrent, stator ground, reverse power, volts per hertz, lossof-field, and undervoltage protection. The protection is housed at the Beta generating plant
and at the Beta substation, and includes the associated relays, voltage and current sensing
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PRC-004-6 Supplemental Material

devices, DC supplies, and control circuitry.
Composite Protection System – Breaker Failure Example
Breaker failure protection provides backup protection for the breaker, and therefore is part of
the breaker’s Composite Protection System. Considering breaker failure protection to be part of
another Element’s Composite Protection System could lead to an incorrect conclusion that a
breaker failure operation automatically satisfies the “Slow Trip” criteria of the Misoperation
definition.
•

An example of a correct operation of the breaker’s Composite Protection System is when
the breaker failure relaying tripped because the line relaying operated, but the breaker
failed to clear the Fault. The breaker failure relaying operated because of a failed trip coil.
The failed trip coil caused a Misoperation of the line’s Composite Protection System.

•

An example of a correct operation of the breaker’s Composite Protection System is when
the breaker failure relaying tripped because the line relaying operated, but the breaker
failed to clear the Fault. Only the breaker failure relaying operated because of a failed
breaker mechanism. This was not a Misoperation because the breaker mechanism is not
part of the breaker’s Composite Protection System.

•

An example of an “Unnecessary Trip – During Fault” is when the breaker failure relaying
tripped at the same time as the line relaying during a Fault. The Misoperation was due to
the breaker failure timer being set to zero.
Misoperation – The failure a Composite Protection System to operate as intended for
protection purposes. Any of the following is a Misoperation:
1. Failure to Trip – During Fault – A failure of a Composite Protection System to operate for
a Fault condition for which it is designed. The failure of a Protection System component
is not a Misoperation as long as the performance of the Composite Protection System is
correct.
2. Failure to Trip – Other Than Fault – A failure of a Composite Protection System to
operate for a non-Fault condition for which it is designed, such as a power swing,
undervoltage, overexcitation, or loss of excitation. The failure of a Protection System
component is not a Misoperation as long as the performance of the Composite
Protection System is correct.
3. Slow Trip – During Fault – A Composite Protection System operation that is slower than
required for a Fault condition if the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System.
4. Slow Trip – Other Than Fault – A Composite Protection System operation that is slower
than required for a non-Fault condition, such as a power swing, undervoltage,
overexcitation, or loss of excitation, if the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System.
5. Unnecessary Trip – During Fault – An unnecessary Composite Protection System
operation for a Fault condition on another Element.
6. Unnecessary Trip – Other Than Fault – An unnecessary Composite Protection System
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PRC-004-6 Supplemental Material

operation for a non-Fault condition. A Composite Protection System operation that is
caused by personnel during on-site maintenance, testing, inspection, construction, or
commissioning activities is not a Misoperation.
The Misoperation definition is based on the principle that an Element’s total complement of
protection is intended to operate dependably and securely.
•

Failure to automatically reclose after a Fault condition is not included as a Misoperation
because reclosing equipment is not included within the definition of Protection System.

•

A breaker failure operation does not, in itself, constitute a Misoperation.

•

A remote backup operation resulting from a “Failure to Trip” or a “Slow Trip” does not, in
itself, constitute a Misoperation.

This proposed definition of Misoperation provides additional clarity over the current version. A
Misoperation is the failure of a Composite Protection System to operate as intended for
protection purposes. The definition includes six categories which provide further differentiation
of what constitutes a Misoperation. These categories are discussed in greater detail in the
following sections.
Failure to Trip – During Fault
This category of Misoperation typically results in the Fault condition being cleared by remote
backup Protection System operation.
Example 1a: A failure of a transformer's Composite Protection System to operate for a
transformer Fault is a Misoperation.
Example 1b: A failure of a "primary" transformer relay (or any other component) to operate
for a transformer Fault is not a “Failure to Trip – During Fault” Misoperation as long as
another component of the transformer's Composite Protection System operated.
Example 1c: A lack of target information does not by itself constitute a Misoperation. When
a high-speed pilot system does not target because a high-speed zone element trips first, it
would not in and of itself be a Misoperation.
Example 1d: A failure of an overall differential relay to operate is not a “Failure to Trip –
During Fault” Misoperation as long as another component such as a generator differential
relay operated.
Example 1e: The Composite Protection System for a bus does not operate during a bus
Fault which results in the operation of all local transformer Protection Systems connected
to that bus and all remote line Protection Systems connected to that bus isolating the
faulted bus from the grid. The operation of the local transformer Protection Systems and
the operation of all remote line Protection Systems correctly provided backup protection.
There is one “Failure to Trip – During Fault” Misoperation of the bus Composite Protection
System.
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In analyzing the Protection System for Misoperation, the entity must also consider whether the
“Slow Trip – During Fault” category applies to the operation.
Failure to Trip – Other Than Fault
This category of Misoperation may have resulted in operator intervention. The “Failure to Trip –
Other Than Fault” conditions cited in the definition are examples only, and do not constitute an
all-inclusive list.
Example 2a: A failure of a generator's Composite Protection System to operate for an
unintentional loss of field condition is a Misoperation.
Example 2b: A failure of an overexcitation relay (or any other component) is not a "Failure
to Trip – Other Than Fault" Misoperation as long as the generator's Composite Protection
System operated as intended isolating the generator from the BES.
In analyzing the Protection System for Misoperation, the entity must also consider whether the
“Slow Trip – Other Than Fault” category applies to the operation.
Slow Trip – During Fault
This category of Misoperation typically results in remote backup Protection System operation
before the Fault is cleared.
Example 3a: A Composite Protection System that is slower than required for a Fault
condition is a Misoperation if the duration of its operating time resulted in the operation of
at least one other Element’s Composite Protection System. The current differential element
of a multiple function relay failed to operate for a line Fault. The same relay's timeovercurrent element operated after a time delay. However, an adjacent line also operated
from a time-overcurrent element. The faulted line's time-overcurrent element was found to
be set to trip too slowly.
Example 3b: A failure of a breaker's Composite Protection System to operate as quickly as
intended to meet the expected critical Fault clearing time for a line Fault in conjunction with
a breaker failure (i.e., stuck breaker) is a Misoperation if it resulted in an unintended
operation of at least one other Element’s Composite Protection System. If a generating
unit’s Composite Protection System operates due to instability caused by the slow trip of
the breaker's Composite Protection System, it is not an “Unnecessary Trip – During Fault”
Misoperation of the generating unit’s Composite Protection System. This event would be a
“Slow Trip – During Fault” Misoperation of the breaker's Composite Protection System.
Example 3c: A line connected to a generation interconnection station is protected with two
independent high-speed pilot systems. The Composite Protection System for this line also
includes step distance and time-overcurrent schemes in addition to the two pilot systems.
During a Fault on this line, the two pilot systems fail to operate and the time-overcurrent
scheme operates clearing the Fault with no generating units or other Elements tripping (i.e.,
no over-trips). This event is not a Misoperation.
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The phrase “slower than required” means the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System. It would be impractical
to provide a precise tolerance in the definition that would be applicable to every type of
Protection System. Rather, the owner(s) reviewing each Protection System operation should
understand whether the speed and outcome of its Protection System operation met their
objective. The intent is not to require documentation of exact Protection System operation
times, but to assure consideration of relay coordination and system stability by the owner(s)
reviewing each Protection System operation.
The phrase “resulted in the operation of any other Composite Protection System” refers to the
need to ensure that relaying operates in the proper or planned sequence (i.e., the primary
relaying for a faulted Element operates before the remote backup relaying for the faulted
Element).
In analyzing the Protection System for Misoperation, the entity must also consider the
“Unnecessary Trip – During Fault” category to determine if an “unnecessary trip” applies to the
Protection System operation of an Element other than the faulted Element.
If a coordination error was at the local terminal (i.e., set too slow), then it was a "Slow Trip,"
category of Misoperation at the local terminal.
Slow Trip – Other Than Fault
The phrase “slower than required” means the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System. It would be impractical
to provide a precise tolerance in the definition that would be applicable to every type of
Protection System. Rather, the owner(s) reviewing each Protection System operation should
understand whether the speed and outcome of its Protection System operation met their
objective. The intent is not to require documentation of exact Protection System operation
times, but to assure consideration of relay coordination and system stability by the owner(s)
reviewing each Protection System operation.
Example 4: A phase to phase fault occurred on the terminals of a generator. The generator's
Composite Protection System and a transmission line's Composite Protection System both
operated in response to the fault. It was found during subsequent investigation that the
generator protection contained an inappropriate time delay. This caused the transmission
line's correctly set overreaching zone of protection to operate. This was a Misoperation of
the generator’s Composite Protection System, but not of the transmission line’s Composite
Protection System.
The “Slow Trip – Other Than Fault” conditions cited in the definition are examples only, and do
not constitute an all-inclusive list.
Unnecessary Trip – During Fault
An operation of a properly coordinated remote Protection System is not in and of itself a
Misoperation if the Fault has persisted for a sufficient time to allow the correct operation of the
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Composite Protection System of the faulted Element to clear the Fault. A BES interrupting
device failure, a “failure to trip” Misoperation, or a “slow trip” Misoperation may result in a
proper remote Protection System operation.
Example 5: An operation of a transformer's Composite Protection System which trips (i.e.,
over-trips) for a properly cleared line Fault is a Misoperation. The Fault is cleared properly
by the faulted equipment's Composite Protection System (i.e., line relaying) without the
need for an external Protection System operation resulting in an unnecessary trip of the
transformer protection; therefore, the transformer Protection System operation is a
Misoperation.
Example 5b: An operation of a line's Composite Protection System which trips (i.e., overtrips) for a properly cleared Fault on a different line is a Misoperation. The Fault is cleared
properly by the faulted line's Composite Protection System (i.e., line relaying); however,
elsewhere in the system, a carrier blocking signal is not transmitted (e.g., carrier ON/OFF
switch found in OFF position) resulting in the operation of a remote Protection System,
single-end trip of a non-faulted line. The operation of the Protection System for the nonfaulted line is an unnecessary trip during a Fault. Therefore, the non-faulted line Protection
System operation is an “Unnecessary Trip – During Fault” Misoperation.
Example 5c: If a coordination error was at the remote terminal (i.e., set too fast), then it
was an "Unnecessary Trip – During Fault" category of Misoperation at the remote terminal.
Unnecessary Trip – Other Than Fault
Unnecessary trips for non-Fault conditions include but are not limited to: power swings,
overexcitation, loss of excitation, frequency excursions, and normal operations.
Example 6a: An operation of a line's Composite Protection System due to a relay failure
during normal operation is a Misoperation.
Example 6b: Tripping a generator by the operation of the loss of field protection during an
off-nominal frequency condition while the field is intact is a Misoperation assuming the
Composite Protection System was not intended to operate under this condition.
Example 6c: An impedance line relay trip for a power swing that entered the relay’s
characteristic is a Misoperation if the power swing was stable and the relay operated
because power swing blocking was enabled and should have prevented the trip, but did not.
Example 6d: Tripping a generator operating at normal load by the operation of a reverse
power protection relay due to a relay failure is a Misoperation.
Additionally, an operation that occurs during a non-Fault condition but was initiated directly by
on-site (i.e., real-time) maintenance, testing, inspection, construction, or commissioning is not a
Misoperation.
Example 6e: A BES interrupting device operation that occurs at the remote end of a line
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during a non-Fault condition because a direct transfer trip was initiated by system
maintenance and testing activities at the local end of the line is not a Misoperation because
of the maintenance exclusion in category 6 of the definition of “Misoperation.”
The “on-site” activities at one location that initiates a trip to another location are included in
this exemption. This includes operation of a Protection System when energizing equipment to
facilitate measurements, such as verification of current circuits as a part of performing
commissioning; however, once the maintenance, testing, inspection, construction, or
commissioning activity associated with the Protection System is complete, the "on-site"
Misoperation exclusion no longer applies, regardless of the presence of on-site personnel.
Special Cases

Protection System operations for these cases would not be a Misoperation.
Example 7a: A generator Protection System operation prior to closing the unit breaker(s) is
not a Misoperation provided no in-service Elements are tripped.
This type of operation is not a Misoperation because the generating unit is not synchronized
and is isolated from the BES. Protection System operations that occur when the protected
Element is out of service and that do not trip any in-service Elements are not Misoperations.
In some cases where zones of protection overlap, the owner(s) of Elements may decide to allow
a Protection System to operate faster in order to gain better overall Protection System
performance for an Element.
Example 7b: The high-side of a transformer connected to a line may be within the zone of
protection of the supplying line’s relaying. In this case, the line relaying is planned to protect
the area of the high-side of the transformer and into its primary winding. In order to
provide faster protection for the line, the line relaying may be designed and set to operate
without direct coordination (or coordination is waived) with local protection for Faults on
the high-side of the connected transformer. Therefore, the operation of the line relaying for
a high-side transformer Fault operated as intended and would not be a Misoperation.
Below are examples of conditions that would be a Misoperation.
Example7c: A 230 kV shunt capacitor bank was released for operational service. The
capacitor bank trips due to a settings error in the capacitor bank differential relay upon
energization.
Example 7d: A 230/115 kV BES transformer bank trips out when being re-energized due to
an incorrect operation of the transformer differential relay for inrush after being released
for operational service. Only the high-side breaker opens since the low-side breaker had not
yet been closed.
Non-Protective Functions

BES interrupting device operations which are initiated by non-protective functions, such as
those associated with generator controls, excitation controls, or turbine/boiler controls, static
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voltampere-reactive compensators (SVC), flexible ac transmission systems (FACTS), high-voltage
dc (HVdc) transmission systems, circuit breaker mechanisms, or other facility control systems
are not operations of a Protection System. The standard is not applicable to non-protective
functions such as automation (e.g., data collection) or control functions that are embedded
within a Protection System.
Control Functions

The entity must make a determination as to whether the standard is applicable to each
operation of its Protection System in accordance with the provided exclusions in the standard’s
Applicability, see Section 4.2.1. The subject matter experts (SME) developing this standard
recognize that entities use Protection Systems as part of a routine practice to control BES
Elements. This standard is not applicable to operation of protective functions within a
Protection System when intended for controlling a BES Element as a part of an entity’s process
or planned switching sequence. The following are examples of conditions to which this standard
is not applicable:
Example 8a: The reverse power protective function that operates to remove a generating
unit from service using the entity’s normal or routine process.
Example 8b: The reverse power relay enables a permissive trip and the generator operator
trips the unit.
The standard is not applicable to operation of the protective relay because its operation is
intended as a control function as part of a controlled shutdown sequence for the generator.
However, the standard remains applicable to operation of the reverse power relay when it
operates for conditions not associated with the controlled shutdown sequence, such as a
motoring condition caused by a trip of the prime mover.
The following is another example of a condition to which this standard is not applicable:
Example 8c: Operation of a capacitor bank interrupting device for voltage control using
functions embedded within a microprocessor based relay that is part of a Protection
System.
The above are examples only, and do not constitute an all-inclusive list to which the standard is
not applicable.
Extenuating Circumstances

In the event of a natural disaster or other extenuating circumstances, the December 20, 2012
Sanction Guidelines of the North American Electric Reliability Corporation, Section 2.8,
Extenuating Circumstances, reads: “In unique extenuating circumstances causing or
contributing to the violation, such as significant natural disasters, NERC or the Regional Entity
may significantly reduce or eliminate Penalties.” The Regional Entities to whom NERC has
delegated authority will consider extenuating circumstances when considering any sanctions in
relation to the timelines outlined in this standard.
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The volume of Protection System operations tend to be sporadic. If a high rate of Protection
System operations is not sustained, utilities will have an opportunity to catch up within the 120
day period.
Requirement Time Periods

The time periods within all the Requirements are distinct and separate. The applicable entity in
Requirement R1 has 120 calendar days to identify whether a BES interrupting device operation
is a Misoperation. Once the applicable entity has identified a Misoperation, it has completed its
performance under Requirement R1. Identified Misoperations with an identified cause become
subject to Requirement R5 and any subsequent Requirements as necessary.
In Requirement R2, the applicable entity has 120 calendar days, based on the date of the BES
interrupting device operation, to provide notification to the other Protection System owners
that meet the circumstances in Parts 2.1 and 2.2. For the case of an applicable entity that was
notified (R3), it has the later of 120 calendar days from the date of the BES interrupting device
operation or 60 calendar days of notification to identify whether its Protection System
components caused a Misoperation.
Once a Misoperation is identified in either Requirement R1 or R3, and the applicable entity did
not identify the cause(s) of the Misoperation, the time period for performing at least one
investigative action every two full calendar quarters begins.
The time period in Requirement R5 begins when the Misoperation cause is first identified. The
applicable entity is allotted 60 calendar days to perform one of the two activities listed in
Requirement R5 (e.g., CAP or declaration) to complete its performance under Requirement R5.
Requirement R6 time period is determined by the actions and the associated timetable to
complete those actions identified in the CAP. The time periods contained in the CAP may
change from time to time and the applicable entity is required to update the timetable when it
changes.
Time periods provided in the Requirements are intended to provide a reasonable amount of
time to perform each Requirement. Performing activities in the least amount of time facilitates
prompt identification of Misoperations, notification to other Protection System owners,
identification of the cause(s), correction of the cause(s), and that important information is
retained that may be lost due to time.
Requirement R1

This Requirement initiates a review of each BES interrupting device operation to identify
whether or not a Misoperation may have occurred. Since the BES interrupting device owner
typically monitors and tracks device operations, the owner is the logical starting point for
identifying Misoperations of Protection Systems for BES Elements. A review is required when
(1) a BES interrupting device operates that is caused by a Protection System or by manual
intervention in response to a Protection System failure to operate, (2) regardless of whether
the owner owns all or part of the Protection System component(s), and (3) the owner identified
its Protection System component(s) as causing the BES interrupting device operation or was
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caused by manual intervention in response to its Protection System failure to operate.
Since most Misoperations result in the operation of one or more BES interrupting devices, these
operations initiate a review to identify any Misoperation. If an Element is manually isolated in
response to a failure to operate, the manual isolation of the Element triggers a review for
Misoperation.
Example R1a: The failure of a loss of field relay on a generating unit where an operator
takes action to isolate the unit.
Manual intervention may indicate a Misoperation has occurred, thus requiring the initiation of
an investigation by the BES interrupting device owner.
For the case where a BES interrupting device did not operate and remote clearing occurs due to
the failure of a Composite Protection System to operate, the BES interrupting device owner
would still review the operation under Requirement R1. However, if the BES interrupting device
owner determines that its Protection System component operated as backup protection for a
condition on another entity’s BES Element, the owner would provide notification of the
operation to the other Protection System owner(s) under Requirement R2, Part 2.2.
Protection Systems are made of many components. These components may be owned by
different entities. For example, a Generator Owner may own a current transformer that sends
information to a Transmission Owner’s differential relay. All of these components and many
more are part of a Protection System. It is expected that all of the owners will communicate
with each other, sharing information freely, so that Protection System operations can be
analyzed, Misoperations identified, and corrective actions taken.
Each entity is expected to use judgment to identify those Protection System operations that
meet the definition of Misoperation regardless of the level of ownership. A combination of
available information from resources such as counters, relay targets, Supervisory Control and
Data Acquisition (SCADA) systems, or DME would typically be used to determine whether or not
a Misoperation occurred. The intent of the standard is to classify an operation as a
Misoperation if the available information leads to that conclusion. In many cases, it will not be
necessary to leverage all available data to determine whether or not a Misoperation occurred.
The standard also allows an entity to classify an operation as a Misoperation if entity is not
sure. The entity may decide to identify the operation as a Misoperation to satisfy Requirement
R1 and continue its investigation for a cause of the Misoperation . If the continued investigative
actions are inconclusive, the entity may declare no cause found and end its investigation. The
entity is allotted 120 calendar days from the date of its BES interrupting device operation to
identify whether its Protection System component(s) caused a Misoperation.
The Protection System operation may be documented in a variety of ways such as in a report,
database, spreadsheet, or list. The documentation may be organized in a variety of ways such
as by BES interrupting device, protected Element, or Composite Protection System.
Repeated operations which occur during the same automatic reclosing sequence do not need a
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separate identification under Requirement R1. Repeated Misoperations which occur during the
same 24-hour period do not need a separate identification under Requirement R1. This is
consistent with the NERC Misoperations Report 7 which states:
“In order to avoid skewing the data with these repeated events, the NERC SPCS should
clarify, in the next annual update of the misoperation template, that all misoperations due
to the same equipment and cause within a 24 hour period be recorded as one
misoperation.”
The following is an example of a condition that is not a Misoperation.
Example R1b: A high impedance Fault occurs within a transformer. The sudden pressure
relaying detects and operates for the Fault, but the differential relaying did not operate due
to the low Fault current levels. This is not a Misoperation because the Composite Protection
System was not required to operate because the Fault was cleared by the sudden pressure
relay.
Requirement R2

Requirement R2 ensures notification of those who have a role in identifying Misoperations, but
were not accounted for within Requirement R1. In the case of multi-entity ownership, the
entity that owns the BES interrupting device that operated is expected to use judgment to
identify those Protection System operations that meet the definition of Misoperation under
Requirement R1; however, if the entity that owns a BES interrupting device determines that its
Protection System component(s) did not cause the BES interrupting device(s) operation or
cannot determine whether its Protection System components caused the BES interrupting
device(s) operation, it must notify the other Protection System owner(s) that share
Misoperation identification responsibility when the criteria in Requirement R2 is met.
This Requirement does not preclude the Protection System owners from initially
communicating and working together to determine whether a Misoperation occurred and, if so,
the cause. The BES interrupting device owner is only required to officially notify the other
owners when it: (1) shares the Composite Protection System ownership with other entity(ies),
(2) determines that a Misoperation occurred or cannot rule out a Misoperation, and (3)
determines its Protection System component(s) did not cause a Misoperation or is unsure.
Officially notifying the other owners without performing a preliminary review may
unnecessarily burden the other owners with compliance obligations under Requirement R3,
redirect valuable resources, and add little benefit to reliability. The BES interrupting device
owner should officially notify other owners when appropriate within the established time
period.
The following is an example of a notification to another Protection System owner:
Example R2a: Circuit breakers A and B at the Charlie station tripped from directional
“Misoperations Report.” Reporting Multiple Occurrences. NERC Protection System Misoperations Task Force.
(http://www.nerc.com/docs/pc/psmtf/PSMTF_Report.pdf). April 1, 2013. Pg. 37 of 40.
7

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comparison blocking (DCB) relaying on 03/03/2014 at 15:43 UTC during an external Fault.
As discussed last week, the fault records indicate that a problem with your equipment
(failure to transmit) caused the operation.
Example R2b: A generator unit tripped out immediately upon synchronizing to the grid due
to a Misoperation of its overcurrent protection. The Transmission Owner owns the 230 kV
generator breaker that operated. The Transmission Owner, as the owner of the BES
interrupting device after determining that its Protection System components did not cause
the Misoperation, notified the Generator Owner of the operation. The Generator Owner
investigated and determined that its Protection System components caused the
Misoperation. In this example, the Generator Owner’s Protection System components did
cause the Misoperation. As the owner of the Protection System components that caused
the Misoperation, the Generator Owner is responsible for creating and implementing the
CAP.
A Composite Protection System owned by different functional entities within the same
registered entity does not necessarily satisfy the notification criteria in Part 2.1.1 of
Requirement R2. For example, if the same personnel within a registered entity perform the
Misoperation identification for both the Generator Owner and Transmission Owner functions,
then the Misoperation identification would be completely covered in Requirement R1, and
therefore notification would not be required. However, if the Misoperation identification is
handled by different groups, then notification would be required because the Misoperation
identification would not necessarily be covered in Requirement R1.
Example R2c: Line A Composite Protection System (owned by entity 1) failed to operate for
an internal Fault. As a result, the zone 3 portion of Line B’s Composite Protection System
(owned by entity 2) and zone 3 portion of Line C’s Composite Protection System (owned by
entity 3) operated to clear the Fault. Entity 2 and 3 notified entity 1 of the remote zone 3
operation.
For the case where a BES interrupting device operates to provide backup protection for a nonBES Element, the entity reviewing the operation is not required to notify the other owners of
Protection Systems for non-BES Elements. No notification is required because this Reliability
Standard is not applicable to Protection Systems for non-BES Elements.
Requirement R3

For Requirement R3 (i.e., notification received), the entity that also owns a portion of the
Composite Protection System is expected to use judgment to identify whether the Protection
System operation is a Misoperation. A combination of available information from resources
such as counters, relay targets, SCADA, DME, and information from the other owner(s) would
typically be used to determine whether or not a Misoperation occurred. The intent of the
standard is to classify an operation as a Misoperation if the available information leads to that
conclusion. In many cases, it will not be necessary to leverage all available data to determine
whether or not a Misoperation occurred. The standard also allows an entity to classify an
operation as a Misoperation if an entity is not sure. The entity may decide to identify the
operation as a Misoperation to satisfy Requirement R1 and continue its investigation for a
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cause of the Misoperation. If the continued investigative actions are inconclusive, the entity
may declare no cause found and end its investigation.
The entity that is notified by the BES interrupting device owner is allotted the later of 60
calendar days from receipt of notification or 120 calendar days from the BES interrupting device
operation date to determine if its portion of the Composite Protection System caused the
Protection System operation. It is expected that in most cases of a jointly owned Protection
System, the entity making notification would have been in communication with the other
owner(s) early in the process. This means that the shorter 60 calendar days only comes into
play if the notification occurs in the second half of the 120 calendar days allotted to the BES
interrupting device owner in Requirement R1.
The Protection System review may be organized in a variety of ways such as in a report,
database, spreadsheet, or list. The documentation may be organized in a variety of ways such
as by BES interrupting device, protected Element, or Composite Protection System. The BES
interrupting device owner’s notification received may be documented in a variety of ways such
as an email or a facsimile.
Requirement R5

Resolving the causes of Protection System Misoperations benefits BES reliability by preventing
recurrence. The Corrective Action Plan (CAP) is an established tool for resolving operational
problems. The NERC Glossary defines a Corrective Action Plan as, "A list of actions and an
associated timetable for implementation to remedy a specific problem." Since a CAP addresses
specific problems, the determination of what went wrong needs to be completed before
developing a CAP. When the Misoperation cause is identified in Requirement R1 or R3,
Requirement R5 requires Protection System owner(s) to develop a CAP, or explain why
corrective actions are beyond the entity’s control or would not improve BES reliability. The
entity must develop the CAP or make a declaration why additional actions are beyond the
entity’s control or would not improve BES reliability and that no further corrective actions will
be taken within 60 calendar days of first determining a cause.
The SMEs developing this standard recognize there may be multiple causes for a Misoperation.
In these circumstances, the CAP would include a remedy for the identified causes. The CAP may
be revised if additional causes are found; therefore, the entity has the option to create a single
or multiple CAP(s) to correct multiple causes of a Misoperation. The 60 calendar day period for
developing a CAP (or declaration) is established on the basis of industry experience which
includes operational coordination timeframes, time to consider alternative solutions,
coordination of resources, and development of a schedule.
The development of a CAP is intended to document the specific corrective actions needed to be
taken to prevent Misoperation recurrence, the timetable for executing such actions, and an
evaluation of the CAP's applicability to the entity’s other Protection Systems including other
locations. The evaluation of these other Protection Systems aims to reduce the risk and
likelihood of similar Misoperations in other Protection Systems. The Protection System owner is
responsible for determining the extent of its evaluation concerning other Protection Systems
and locations. The evaluation may result in the owner including actions to address Protection
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Systems at other locations or the reasoning for not taking any action. The CAP and an
evaluation of other Protection Systems including other locations must be developed to
complete Requirement R5.
The following is an example of a CAP for a relay Misoperation that was applying a standing trip
due to a failed capacitor within the relay and the evaluation of the cause at similar locations
which determined capacitor replacement was not necessary.
For completion of each CAP in Examples R5a through R5d, please see Examples R6a through
R6d.
Example R5a: Actions: Remove the relay from service. Replace capacitor in the relay. Test
the relay. Return to service or replace by 07/01/2014.
Applicability to other Protection Systems: This type of impedance relay has not been
experiencing problems and is systematically being replaced with microprocessor relays as
Protection Systems are modernized. Therefore, it was assessed that a program for
wholesale preemptive replacement of capacitors in this type of impedance relay does not
need to be established for the system.
The following is an example of a CAP for a relay Misoperation that was applying a standing trip
due to a failed capacitor within the relay and the evaluation of the cause at similar locations
which determined the capacitors need preemptive correction action.
Example R5b: Actions: Remove the relay from service. Replace capacitor in the relay. Test
the relay. Return to service or replace by 07/01/2014.
Applicability to other Protection Systems: This type of impedance relay is suspected to have
previously tripped at other locations because of the same type of capacitor issue. Based on
the evaluation, a program should be established by 12/01/2014 for wholesale preemptive
replacement of capacitors in this type of impedance relay.
The following is an example of a CAP for a relay Misoperation that was applying a standing trip
due to a failed capacitor within the relay and the evaluation of the cause at similar locations
which determined the capacitors need preemptive correction action.
Example R5c: Actions: Remove the relay from service. Replace capacitor in the relay. Test
the relay. Return to service or replace by 07/01/2014.
Applicability to other Protection Systems: This type of impedance relay is suspected to have
previously tripped at other locations because of the same type of capacitor issue. Based on
the evaluation, the preemptive replacement of capacitors in this type of impedance relay
should be pursued for the identified stations A through I by 04/30/2015.
A plan is being developed to replace the impedance relay capacitors at stations A, B, and C
by 09/01/2014. A second plan is being developed to replace the impedance relay capacitors
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at stations D, E, and F by 11/01/2014. The last plan will replace the impedance relay
capacitors at stations G, H, and I by 02/01/2015.
The following is an example of a CAP for a relay Misoperation that was due to a version 2
firmware problem and the evaluation of the cause at similar locations which determined the
firmware needs preemptive correction action.
Example R5d: Actions: Provide the manufacturer fault records. Install new firmware
pending manufacturer results by 10/01/2014.
Applicability to other Protection Systems: Based on the evaluation of other locations and a
risk assessment, the newer firmware version 3 should be installed at all installations that
are identified to be version 2. Twelve relays were identified across the system. Proposed
completion date is 12/31/2014.
The following are examples of a declaration made where corrective actions are beyond the
entity’s control or would not improve BES reliability and that no further corrective actions will
be taken.
Example R5e: The cause of the Misoperation was due to a non-registered entity
communications provider problem.
Example R5f: The cause of the Misoperation was due to a transmission transformer tapped
industrial customer who initiated a direct transfer trip to a registered entity’s transmission
breaker.
In situations where a Misoperation cause emanates from a non-registered outside entity, there
may be limited influence an entity can exert on an outside entity and is considered outside of
an entity’s control.
The following are examples of declarations made why corrective actions would not improve BES
reliability.
Example R5g: The investigation showed that the Misoperation occurred due to transients
associated with energizing transformer ABC at Station Y. Studies show that de-sensitizing
the relay to the recorded transients may cause the relay to fail to operate as intended
during power system oscillations.
Example R5h: As a result of an operation that left a portion of the power system in an
electrical island condition, circuit XYZ within that island tripped, resulting in loss of load
within the island. Subsequent investigation showed an overfrequency condition persisted
after the formation of that island and the XYZ line protective relay operated. Since this relay
was operating outside of its designed frequency range and would not be subject to this
condition when line XYZ is operated normally connected to the BES, no corrective action will
be taken because BES reliability would not be improved.
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Example R5i: During a major ice storm, four of six circuits were lost at Station A.
Subsequent to the loss of these circuits, a skywire (i.e., shield wire) broke near station A on
line AB (between Station A and B) resulting in a phase-phase Fault. The protection scheme
utilized for both protection groups is a permissive overreaching transfer trip (POTT). The
Line AB protection at Station B tripped timed for this event (i.e., Slow Trip – During Fault)
even though this line had been identified as requiring high speed clearing. A weak infeed
condition was created at Station A due to the loss of 4 transmission circuits resulting in the
absence of a permissive signal on Line AB from Station A during this Fault. No corrective
action will be taken for this Misoperation as even under N-1 conditions, there is normally
enough infeed at Station A to send a proper permissive signal to station B. Any changes to
the protection scheme to account for this would not improve BES reliability.
A declaration why corrective actions are beyond the entity’s control or would not improve BES
reliability should include the Misoperation cause and the justification for taking no corrective
action. Furthermore, a declaration that no further corrective actions will be taken is expected
to be used sparingly.
Requirement R6

To achieve the stated purpose of this standard, which is to identify and correct the causes of
Misoperations of Protection Systems for BES Elements, the responsible entity is required to
implement a CAP that addresses the specific problem (i.e., cause(s) of the Misoperation)
through completion. Protection System owners are required in the implementation of a CAP to
update it when actions or timetable change, until completed. Accomplishing this objective is
intended to reduce the occurrence of future Misoperations of a similar nature, thereby
improving reliability and minimizing risk to the BES.
The following is an example of a completed CAP for a relay Misoperation that was applying a
standing trip (See also, Example R5a).
Example R6a: Actions: The impedance relay was removed from service on 06/02/2014
because it was applying a standing trip. A failed capacitor was found within the impedance
relay and replaced. The impedance relay functioned properly during testing after the
capacitor was replaced. The impedance relay was returned to service on 06/05/2014.
CAP completed on 06/25/2014.
The following is an example of a completed CAP for a relay Misoperation that was applying a
standing trip that resulted in the correction and the establishment of a program for further
replacements (See also, Example R5b).
Example R6b: Actions: The impedance relay was removed from service on 06/02/2014
because it was applying a standing trip. A failed capacitor was found within the impedance
relay and replaced. The impedance relay functioned properly during testing after the
capacitor was replaced. The impedance relay was returned to service on 06/05/2014.
A program for wholesale preemptive replacement of capacitors in this type of impedance
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PRC-004-6 Supplemental Material

relay was established on 10/28/2014.
CAP completed on 10/28/2014.
The following is an example of a completed CAP of corrective actions with a timetable that
required updating for a failed relay and preemptive actions for similar installations (See also,
Example R5c).
Example R6c: Actions: The impedance relay was removed from service on 06/02/2014
because it was applying a standing trip. A failed capacitor was found within the impedance
relay and replaced. The impedance relay functioned properly during testing after the
capacitor was replaced. The impedance relay was returned to service on 06/05/2014.
The impedance relay capacitor replacement was completed at stations A, B, and C on
08/16/2014. The impedance relay capacitor replacement was completed at stations D, E,
and F on 10/24/2014. The impedance relay capacitor replacement for stations G, H, and I
were postponed due to resource rescheduling from a scheduled 02/01/15 completion to
04/01/2015 completion. Capacitor replacement was completed on 03/09/2015 at stations
G, H, and I. All stations identified in the evaluation have been completed.
CAP completed on 03/09/2015.
The following is an example of a completed CAP for corrective actions with updated actions for
a firmware problem and preemptive actions for similar installations. (See also, Example R5d).
Example R6d: Actions: fault records were provided to the manufacturer on 06/04/2014. The
manufacturer responded that the Misoperation was caused by a bug in version 2 firmware,
and recommended installing version 3 firmware. Version 3 firmware was installed on
08/12/2014.
Nine of the twelve relays were updated to version 3 firmware on 09/23/2014. The
manufacturer provided a subsequent update which was determined to be beneficial for the
remaining relays. The remaining three of twelve relays identified as having the version 2
firmware were updated to version 3.01 firmware on 11/10/2014.
CAP completed on 11/10/2014.
The CAP is complete when all of the actions identified within the CAP have been completed.

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PRC-004-6 Supplemental Material

Process Flow Chart: Below is a graphical representation demonstrating the relationships
between Requirements:
Entry Point(s)

(Notified Entities)

(2.1) The owner of a BES interrupting device
that operated, within 120 calendar days of
the BES interrupting device operation

BES interrupting device owner

The owner of a BES interrupting device that operated, within 120
calendar days of the BES interrupting device operation
Operation was caused
by a Protection System
or by manual
intervention in
response to a
Protection System
failure to operate

BES interrupting
device owner
owns all or part
of the Protection
System
component(s)

BES interrupting device owner must
also consider this as a parallel path if a
Composite Protection System has multiple owners

BES interrupting device
owner identified that its
Protection System
component(s) caused the
BES interrupting device(s)
operation or by manual
intervention

BES
interrupting
device owner
shares the
Composite
Protection
System
ownership
with other
entity(ies)

BES
interrupting
device owner
determined
that a
Misoperation
occurred or
cannot rule
out a
Misoperation

R2
R1

BES interrupting
device owner
determined
that its
Protection
System
component(s)
did not cause
the operation
or is unsure

When
all are
TRUE

When
all are
TRUE

Shall identify whether BES interrupting device owner’s Protection
System component(s) caused a Misoperation

Shall notify the other
owner(s) of the Protection
System of the BES
interrupting device
operation

The entity that owns the Protection System component that caused
the Misoperation, within 60 calendar days of first identifying a cause

YES

Stop

Corrective
actions are beyond the
entity’s control or would
not improve BES
reliability?

R5
Reserved. An entity that has not determined the cause(s) of a
Misoperation shall perform at least one investigative action to
determine the cause(s) of the Misoperation, at least once every two
full calendar quarters after the Misoperation was first identified,
until one of the following completes the investigation:
Stop
Write a
declaration
that no cause
was identified

R4
NO

Cause
Found?

YES

YES
(2.2)

The entity that receives notification, within the later of
either 60 calendar days of notification or 120 calendar
days of the BES interrupting device(s) operation, shall
identify whether its Protection System component(s)
caused a Misoperation.

R3

Is a
Misop?

NO

Remote
Backup
Protection
Operated?

NO

Cause
identified

YES

NO
Develop a CAP and
an evaluation

Stop

Stop

Implement each Corrective
Action Plan (CAP), and update
each CAP if actions or
timetables change, until
completed.

R6

Document why
corrective actions are
beyond the entity’s
control or would not
improve BES reliability,
and that no further
corrective actions will
be taken

YES
CAP
complete?
NO

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