RM22-16, NERC Proposed Standard

Exhibit A
Proposed Reliability Standards and Definitions

Exhibit A-1
Proposed Reliability Standard PRC-027-1

PRC-027-1 — Coordination of Protection Systems for Performance During Faults

A. Introduction
1.

Title:

Coordination of Protection Systems for Performance During Faults

2.

Number: PRC-027-1

3.

Purpose: To maintain the coordination of Protection Systems installed to detect and
isolate Faults on Bulk Electric System (BES) Elements, such that those Protection
Systems operate in the intended sequence during Faults.

4.

Applicability:
4.1. Functional Entities:
4.1.1.

Transmission Owner

4.1.2.

Generator Owner

4.1.3.

Distribution Provider (that owns Protection Systems identified in the
Facilities section 4.2 below)

4.2. Facilities: Protection Systems installed to detect and isolate Faults on BES
Elements.
5.

Effective Date: See the Implementation Plan for PRC-027-1, Project 2007-06 System
Protection Coordination.

B. Requirements and Measures
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish
a process for developing new and revised Protection System settings for BES Elements,
such that the Protection Systems operate in the intended sequence during Faults. The
process shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
1.1. A review and update of short-circuit model data for the BES Elements under
study.
1.2. A review of the developed Protection System settings.
1.3. For Protection System settings applied on BES Elements that electrically join
Facilities owned by separate functional entities (Transmission Owners, Generator
Owners, and Distribution Providers), provisions to:
1.3.1. Provide the proposed Protection System settings to the owner(s) of the
electrically joined Facilities.
1.3.2. Respond to any owner(s) that provided its proposed Protection System
settings pursuant to Requirement R1, Part 1.3.1 by identifying any
coordination issue(s) or affirming that no coordination issue(s) were
identified.

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PRC-027-1 — Coordination of Protection Systems for Performance During Faults

1.3.3. Verify that identified coordination issue(s) associated with the proposed
Protection System settings for the associated BES Elements are addressed
prior to implementation.
1.3.4. Communicate with the other owner(s) of the electrically joined Facilities
regarding revised Protection System settings resulting from unforeseen
circumstances that arise during implementation or commissioning,
Misoperation investigations, maintenance activities, or emergency
replacements required as a result of Protection System component
failure.
M1. Acceptable evidence may include, but is not limited to, dated electronic or hard copy
documentation to demonstrate that the responsible entity established a process to
develop settings for its Protection Systems, in accordance with Requirement R1.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall, for each
BES Element with Protection System functions identified in Attachment A: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
•
•

•

Option 1: Perform a Protection System Coordination Study in a time interval
not to exceed six-calendar years; or
Option 2: Compare present Fault current values to an established Fault current
baseline and perform a Protection System Coordination Study when the
comparison identifies a 15 percent or greater deviation in Fault current values
(either three phase or phase to ground) at a bus to which the BES Element is
connected, all in a time interval not to exceed six-calendar years; 1 or,
Option 3: Use a combination of the above.

M2. Acceptable evidence may include, but is not limited to, dated electronic or hard copy
documentation to demonstrate that the responsible entity performed Protection
System Coordination Study(ies) and/or Fault current comparisons in accordance with
Requirement R2.
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall utilize its
process established in Requirement R1 to develop new and revised Protection System
settings for BES Elements. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]

1

The initial Fault current baseline(s) shall be established by the effective date of this Reliability Standard and
updated each time a Protection System Coordination Study is performed. The Fault current baseline for BES
generating resources may be established at the generator, the generator step-up (GSU) transformer(s), or at the
common point of connection at 100 kV or above. For dispersed power producing resources, the Fault current
baseline may also be established at the BES aggregation point (total capacity greater than 75 MVA). If an initial
baseline was not established by the effective date of this Reliability Standard because of the previous use of an
alternate option or the installation of a new BES Element, the entity may establish the baseline by performing a
Protection System Coordination Study.
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PRC-027-1 — Coordination of Protection Systems for Performance During Faults

M3. Acceptable evidence may include, but is not limited to, dated electronic or hard copy
documentation to demonstrate that the responsible entity utilized its settings
development process established in Requirement R1, as specified in Requirement R3.
C. Compliance
1.

Compliance Monitoring Process
1.1.

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

1.2.

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 keep data or evidence to show compliance with Requirements R1, R2,
and R3, and Measures M1, M2, and M3 since the last audit, unless directed by
its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
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 completed and approved, or for the time specified above,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records 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-027-1 — Coordination of Protection Systems for Performance During Faults

Violation Severity Levels
R#

Violation Severity Levels
Lower VSL

R1.

N/A

Moderate VSL

The responsible entity
established a process in
accordance with
Requirement R1, but failed
to include Requirement R1,
Part 1.1 or Part 1.2.

High VSL

The responsible entity
established a process in
accordance with
Requirement R1, but failed
to include Requirement R1,
Part 1.1 and Part 1.2.

Severe VSL

The responsible entity
established a process in
accordance with
Requirement R1, but failed
to include Requirement R1,
Part 1.3.
OR
The responsible entity failed
to establish any process in
accordance with
Requirement R1.

R2.

The responsible entity
performed a Protection
System Coordination Study
for each BES Element, in
accordance with
Requirement R2, Option 1,
Option 2, or Option 3 but
was late by less than or
equal to 30 calendar days.

The responsible entity
performed a Protection
System Coordination Study
for each BES Element, in
accordance with
Requirement R2, Option 1,
Option 2, or Option 3, but
was late by more than 30
calendar days but less than
or equal to 60 calendar days.

The responsible entity
performed a Protection
System Coordination Study
for each BES Element, in
accordance with
Requirement R2, Option 1,
Option 2, or Option 3, but
was late by more than 60
calendar days but less than
or equal to 90 calendar days.

The responsible entity
performed a Protection
System Coordination Study
for each BES Element, in
accordance with
Requirement R2, Option 1,
Option 2, or Option 3, but
was late by more than 90
calendar days.
OR
The responsible entity failed
to perform Option 1, Option

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PRC-027-1 — Coordination of Protection Systems for Performance During Faults

2, or Option 3, in accordance
with Requirement R2.
R3.
N/A

N/A

N/A

The responsible entity failed
to utilize the process
established in accordance
with Requirement R1.

D. Regional Variances
None.
E. Associated Documents
NERC System Protection and Control Subcommittee – “Power Plant and Transmission System Protection Coordination.”
NERC System Protection and Control Task Force, December 7, 2006, “Assessment of Standard PRC-001-0 – System Protection
Coordination.”
NERC System Protection and Control Task Force, September 2006, “The Complexity of Protecting Three-Terminal Transmission
Lines.”
Version History
Version

Date

1

November 5,
2015

Action
Adopted by NERC Board of Trustees

Change Tracking
New standard developed under Project
2007-06

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PRC-027-1 — Coordination of Protection Systems for Performance During Faults

Attachment A
The following Protection System functions2 are applicable to Requirement R2 if: (1) available Fault current levels are used to develop
the settings for those Protection System functions; and (2) those Protection System functions require coordination with other
Protection Systems.
21 – Distance if:
• infeed is used in determining reach (phase and ground distance), or
• zero-sequence mutual coupling is used in determining reach (ground distance).
50 – Instantaneous overcurrent
51 – AC inverse time overcurrent
67 – AC directional overcurrent if used in a non-communication-aided protection scheme
Notes:
1. The above Protection System functions utilize current in their measurement to initiate tripping of circuit breakers. Changes in
the magnitude of available Fault current can impact the coordination of these functions.
2. See the PRC-027-1 Supplemental Material section for additional information.

2

ANSI/IEEE Standard C37.2 Standard for Electrical Power System Device Function Numbers, Acronyms, and Contact Designations.
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PRC-027-1 Supplemental Material
Purpose
The Purpose states: To maintain the coordination of Protection Systems installed to detect and
isolate Faults on Bulk Electric System (BES) Elements, such that those Protection Systems
operate in the intended sequence during Faults.
Coordinated Protection Systems enhance reliability by isolating faulted equipment, reducing
the risk of BES instability or Cascading, and leaving the remainder of the BES operational and
more capable of withstanding the next Contingency. When Faults occur, properly coordinated
Protection Systems minimize the number of BES Elements that are removed from service and
protect equipment from damage. This standard requires that entities establish and implement
a process to coordinate their Protection Systems to operate in the intended sequence during
Faults.
Applicability
Transmission Owners, Generator Owners, and Distribution Providers are included in the
Applicability of PRC-027-1 because they may own Protection Systems that are installed for the
purpose of detecting Faults on the Bulk Electric System (BES). It is only those Protection
Systems that are under the purview of this standard.
Transmission Owners are included in the Applicability of PRC-027-1 because they own the
largest number of Protection Systems installed for the purpose of detecting Faults on the BES.
Generator Owners have Protection Systems installed for the purpose of detecting Faults on the
BES. It is important that those Protection Systems are coordinated with Protection Systems
owned by Transmission Owners to ensure that generation Facilities do not become
disconnected from the BES unnecessarily. Functions such as impedance reaches, overcurrent
pickups, and time delays need to be evaluated for coordination.
A Distribution Provider may provide an electrical interconnection and path to the BES for
generators that will contribute current to Faults that occur on the BES. If the Distribution
Provider owns Protection Systems that operate for those Faults, it is important that those
Protection Systems are coordinated with other Protection Systems that can be impacted by the
current contribution to the Fault of Distribution Provider.
After the Protection Systems of Distribution Providers and Generator Owners are shown to be
coordinated with other Protection Systems on the BES, there will be little future impact on the
entities unless there are significant changes at or near the bus that interconnects with the
Transmission Owner. The Transmission Owner, which is typically the entity maintaining the
system model for Fault studies, will provide the Fault current data upon request by the
Distribution Provider or Generator Owner. The Distribution Provider and Generator Owner will
determine whether a change in Fault current from the baseline has occurred such that a review
of coordination is necessary.
Requirement R1
The requirement states: Each Transmission Owner, Generator Owner, and Distribution Provider
shall establish a process for developing new and revised Protection System settings for BES
Elements, such that the Protection Systems operate in the intended sequence during Faults.

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PRC-027-1 Supplemental Material
The reliability objective of this requirement is to have applicable entities establish a process to
develop settings for coordinating their Protection Systems, such that they operate in the
intended sequence during Faults. The parts that are included as elements of the process ensure
the development of accurate settings, as well as providing internal and external checks to
minimize the possibility of errors that could be introduced in the development of settings.
This standard references various publications that discuss protective relaying theory and
application. The description of “coordination of protection” is from the pending revision of IEEE
Standard C37.113-1999 (Reaffirmed: 2004), Guide for Protective Relay Applications to
Transmission Lines, which reads:
“The process of choosing current or voltage settings, or time delay characteristics of
protective relays such that their operation occurs in a specified sequence so that interruption
to customers is minimized and least number of power system elements are isolated
following a system fault.”
Entities may have differing technical criteria for the development of Protection System settings
based on their own philosophies. These philosophies can vary based on system topology,
protection technology utilized, as well as historical knowledge; as such, a single definition or
criterion for “Protection System coordination” is not practical.
The coordination of some Protection Systems may seem unnecessary, such as for a line that is
protected solely by dual current differential relays. However, backup Protection Systems that
are enabled to operate based on current or apparent impedance with some definite or inverse
time delay must be coordinated with other Protection Systems of the BES Element such that
tripping does not unnecessarily occur for Faults outside of the differential zone.
Part 1.1

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

The short-circuit study provides the necessary Fault currents used by protection engineers to
develop Protection System settings for Transmission Owners, Generator Owners, and
Distribution Providers. Generator Owners and Distribution Providers may not have or maintain
short-circuit models; consequently, these entities would obtain the short-circuit model data
from the Transmission Planners, Planning Coordinators, or Transmission Owners. Including a
review and, if necessary, an update of short-circuit study information is necessary to ensure
that information accurately reflects the physical power system that will form the basis of the
Protection System Coordination Study and development of Protection System relay settings.
The results of a short-circuit study are only as accurate as the information that its calculations
are based on.
A short-circuit study is an analysis of an electrical network that determines the magnitude of
the currents flowing in the network during an electrical Fault. Because the results of shortcircuit studies are used as the basis for protective device coordination studies, the short-circuit
model should accurately reflect the physical power system.
Reviews could include:
1. A review of applicable BES line, transformer, and generator impedances and Fault currents.

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PRC-027-1 Supplemental Material
2. A review of the network model to confirm the network in the study accurately reflects the
configuration of the actual System, or how the System will be configured when the
proposed relay settings are installed.
3. A review, where applicable, of interconnected Transmission Owner, Generator Owner, and
Distribution Provider information.
Part 1.2

A review of the developed Protection System settings.

A review of the Protection System settings prior to implementation reduces the possibility of
introducing human error. A review is any systematic process of verifying the developed settings
meet the technical criteria of the entity. Examples of reviews include peer reviews, automated
checking programs, and entity-developed review procedures.
Part 1.3

For Protection System settings applied on BES Elements that electrically join
Facilities owned by separate functional entities (Transmission Owners, Generator
Owners, and Distribution Providers), provisions to:

Requirement R1, Part 1.3 addresses the coordination of Protection System settings applied on
BES Elements that electrically join Facilities owned by separate functional entities.
Communication among these entities is essential so potential Protection System coordination
issues can be identified and addressed prior to implementation of any proposed Protection
System changes.
Part 1.3.1
1.3.1. Provide the proposed Protection System settings to the owners of
the electrically joined Facilities.
Requirement R1, Part 1.3.1 requires the entity to include in its process a provision to provide
proposed Protection System settings to other entities. This communication ensures that the
other entities have the necessary information to review the settings and determine if there are
any Protection System coordination issues.
Part 1.3.2
Respond to any owner(s) that provided its proposed Protection System
settings pursuant to Requirement R1, Part 1.3.1 by identifying any coordination issue(s)
or affirming that no coordination issue(s) were identified.
Requirement R1, Part 1.3.2 requires the entity receiving proposed Protection System settings to
include in its process a provision to respond to the entity that initiated the proposed changes.
This ensures that the proposed settings are reviewed and that the initiating entity receives a
response indicating Protection System coordination issues were identified, or affirmation that
no issues were identified.
Part 1.3.3
Verify that identified coordination issue(s) associated with the proposed
Protection System settings for the associated BES Elements are addressed prior to
implementation.
Requirement R1, Part 1.3.3 requires the entity to include in their process a provision to verify
that any identified coordination issue(s) associated with the proposed Protection System
settings are addressed prior to implementation. This ensures that any potential impact to BES
reliability is minimized.

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PRC-027-1 Supplemental Material
The exclusion in PRC-001-1.1(ii), Requirement R3, R3.1 for dispersed power producing
resources applies only to interconnections between different functional entities. As such, the
exclusion only maps to Requirement R1, Part 1.3 in PRC-027-1. Due to the design of dispersed
generation sites, the Protection Systems applied on the individual dispersed generation
resources are not electrically joined Facilities owned by separate functional entities as specified
in Requirement R1, Part 1.3 nor are they connected by BES Elements. Therefore Requirement
R1, Part 1.3 does not apply to the Protection Systems applied on the individual dispersed
generation resources. Requirement R1, Part 1.3 applies only to the Protection Systems applied
on the BES Elements that electrically join Facilities owned by separate functional entities.
Note: There could be instances where coordination issues are identified and the entities agree
not to mitigate all of the issues based on engineering judgment. It is also recognized that
coordination issues identified during a project may not be immediately resolved if the
resolution involves additional system modifications not identified in the initial project scope.
Further, there could be situations where protection philosophies differ between entities, but
the entities can agree that these differences do not create coordination issues.
Part 1.3.4
Communicate with the other owner(s) of the electrically joined Facilities
regarding revised Protection System settings resulting from unforeseen circumstances
that arise during implementation or commissioning, Misoperation investigations,
maintenance activities, or emergency replacements required as a result of Protection
System component failure.
Requirement R1, Part 1.3.4 requires the entity to communicate revisions to Protection System
settings that occur due to unforeseen circumstances and differ from those developed during
the planning stages of projects.
Requirement R2
This requirement states: Each Transmission Owner, Generator Owner, and Distribution Provider
shall, for each BES Element with Protection System functions identified in Attachment A:
•

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

•

Option 2: Compare present Fault current values to an established Fault current
baseline and perform a Protection System Coordination Study when the comparison
identifies a 15 percent or greater deviation in Fault current values (either three
phase or phase to ground) at a bus to which the BES Element is connected, all in a
time interval not to exceed six-calendar years; 3 or,

3

The initial Fault current baseline(s) shall be established by the effective date of this Reliability Standard and
updated each time a Protection System Coordination Study is performed. The Fault current baseline for BES
generating resources may be established at the generator, the generator step-up (GSU) transformer(s), or at the
common point of connection at 100 kV or above. For dispersed power producing resources, the Fault current
baseline may also be established at the BES aggregation point (total capacity greater than 75 MVA). If an initial
baseline was not established by the effective date of this Reliability Standard because of the previous use of an
alternate option or the installation of a new BES Element, the entity may establish the baseline by performing a
Protection System Coordination Study.
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PRC-027-1 Supplemental Material
•

Option 3: Use a combination of the above.

Over time, incremental changes in Fault current can accumulate enough to impact the
coordination of Protection System functions affected by Fault current. To minimize this risk,
Requirement R2 requires responsible entities to periodically (1) perform Protection System
Coordination Studies and/or (2) review available Fault currents for those Protection System
functions listed in Attachment A. Two triggers were established for initiating a review of
existing Protection System settings to allow for industry flexibility.
In the first option, an entity may choose a time-based methodology to review Protection
System settings, thus eliminating the necessity of establishing a Fault current baseline and
periodically performing Fault current comparisons. This option provides the entity the flexibility
to choose an interval of up to six-calendar years for performing the Protection System
Coordination Studies for those Protection System functions in Attachment A. The six-calendaryear time interval was selected as a balance between the manpower required to perform the
studies and the potential reliability impacts created by incremental changes of Fault current
over time.
The second option allows the entity to periodically check for a 15 percent or greater deviation
in Fault current (either three-phase or phase-to-ground) from an established Fault current
baseline for Protection Systems at each bus to which a BES Element is connected. Fault current
baseline values can be obtained from the short-circuit studies performed by the Transmission
Planners, Planning Coordinators, or Transmission Owners. This option allows the entity to
choose an interval of up to six-calendar years to perform the Fault current comparisons and
Protection System Coordination Studies. The six-calendar-year time interval was selected as a
balance between the manpower required to perform the studies and the potential reliability
impacts created by incremental changes of Fault current over time.
The accumulation of these incremental changes could affect the performance of Protection
Systems during Fault conditions. A maximum Fault current deviation of 15 percent (when
compared to the entity-established baseline) was established based on generally-accepted
margins for setting Protection Systems in which incremental Fault current changes would not
interfere with coordination. The 15 percent maximum deviation provides an entity with latitude
to choose a Fault current threshold that best matches its protection philosophy, or other
business considerations. The Fault current based option requires an entity to first establish a
Fault current baseline to be used as a point of reference for future Fault current studies. The
Fault current values used in the percent change calculation, whether three-phase or phase-toground Fault currents, are typically determined with all generation in service and all
transmission BES Elements in their normal operating state.
As described in the footnote for Requirement R2, Option 2, an entity that elects to initially use
Option 2 must establish its baseline prior to the effective date of the standard. If an initial
baseline was not established by the effective date of this Reliability Standard because of the
previous use of an alternate option or the installation of a new BES Element, the entity may
establish the baseline upon performing a Protection System Coordination Study. The Fault
current baseline values can be updated or established when a Protection System Coordination
Study is performed. The baseline values at each bus to which a BES Element is connected are
updated whenever a new Protection System Coordination Study is performed for the subject
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PRC-027-1 Supplemental Material
Protection System. The footnote also states that the Fault current baselines may be established
for BES generating resources at the generator, the BES aggregation point for dispersed power
producing resources, or at the common point of connection at 100 kV or above.
Example: Prior to the effective date of PRC-027-1, an entity intending to use Option 2 of
Requirement R2 establishes an initial baseline; e.g., 10,000 amps at the bus to which the
BES Element under study is connected. A short-circuit review performed on March 1,
2024, for example, identifies that the Fault current has increased to 11,250 amps (12.5
percent deviation); consequently, no Protection System Coordination Study is required
since the increase is below the maximum 15 percent deviation. The baseline value for
the next comparison (to be performed no later than December 31, 2030) remains at
10,000 amps because no study was required as a result of the initial comparison. During
the next six-year interval, Fault current comparison identifies that the Fault current has
increased to 11,500 (15 percent deviation); therefore, a Protection System Coordination
Study is required (and must also be completed no later than December 31, 2030), and a
new baseline of 11,500 amps would be established.
Note: In the first review described above, if the entity decides to perform a Protection
System Coordination Study at the 12.5 percent deviation and the results of the study
indicate that the settings still meet the setting criteria of the entity, then no settings
changes are required and the baseline Fault current(s) would be updated.
As a third option, an entity has the flexibility to apply a combination of the two methodologies.
For example, an entity may choose the periodic Protection System review (Option 1) and
review its Facilities operated above 300 kV on a six-calendar-year interval, while choosing to
use the Fault current comparison (Option 2) for its Facilities operated below 300 kV.
The Protection System functions listed in Attachment A utilize AC current in their measurement
to initiate tripping of circuit breakers and the coordination of these functions is susceptible to
changes in the magnitude of available short-circuit Fault current. These functions are included
in Attachment A based on meeting the following criteria: (1) available Fault current levels are
used to develop settings, and (2) the functions require coordination with other Protection
Systems. Examples of functions not included in Attachment A because they do not meet both of
the criteria are differential relays and Fault detectors. The numerical identifiers in Attachment A
represent general device functions according to ANSI/IEEE Standard C37.2 Standard for
Electrical Power System Device Function Numbers, Acronyms, and Contact Designations.
The following provide additional information regarding the Protection System functions in
Attachment A.
A “51 – AC inverse time overcurrent” relay connected to a CT on the neutral of a generator
step-up transformer, referred to as “51N – AC Inverse Time Earth Overcurrent Relay (Neutral CT
Method)” in ANSI/IEEE Standard C37.2, would be included in a Protection System Coordination
Study. Also applicable, are “51 – AC Inverse time overcurrent” relays connected to CTs on the
phases of an autotransformer for through-fault protection. Overcurrent functions used in
conjunction with other functions are to be reviewed as well. An example is a definite-time
overcurrent function, which is a “50 – Instantaneous overcurrent” function used in conjunction
with a “62 – Time-delay” function.
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PRC-027-1 Supplemental Material
If the functions listed in Attachment A are used in conjunction with other functions, they would
be included in a Protection System Coordination Study provided they require coordination with
other Protection Systems. An example of this is a time-delayed “21 – Distance” function, which
is a “21 – Distance” function with a “62 – Time-delay” function. Another example would be a
definite-time overcurrent function, which is a “50 – Instantaneous overcurrent” function with a
“62 – Time-delay” function. A “50 – Instantaneous overcurrent” function used for supervising a
“21 – Distance” function would not be included in a Protection System Coordination Study as it
does not require coordination with other Protection Systems.
Reviewing “21 – Distance” functions is limited to those applied for phase and ground distance
where infeed is used in determining the phase or ground distance setting when zero-sequence
mutual coupling is used in determining the setting. Where infeed is not used in determining the
setting, “21 – Distance” functions would not be included in a Protection System Coordination
Study, as the reach is not susceptible to changes in the magnitude of available short-circuit
Fault current. Where infeed is used in determining the reach, coordination can be affected by
changes in the magnitude of available short-circuit Fault current. Two examples where infeed
may be used in determining the reach, are protection for a transmission line with a long tap and
a three-terminal transmission line. Ground distance functions are influenced by zero-sequence
mutual coupling. The ground distance measurement can appear to be greater than or less than
the true distance to a Fault when there is zero-sequence mutual coupling. The influence of
zero-sequence mutual coupling changes with the magnitude of available short-circuit current.
Therefore, “21 – Distance” functions would be included in a Protection System Coordination
Study, when zero-sequence mutual coupling is used in determining the setting.
The 67 – AC directional overcurrent function utilized in Protection Systems for Transmission
lines can be instantaneous overcurrent, inverse time overcurrent, or both instantaneous
overcurrent and inverse time overcurrent. For example, in a communication-aided directional
comparison blocking (DCB) scheme, the instantaneous overcurrent function is set very
sensitive. When a single line-to-ground Fault occurs on a Transmission line, the Fault is
detected by a number of Protection Systems for other Transmission lines. Signals from
communication equipment are transmitted and received to block the other Protection Systems
for the non-faulted Transmission lines from operating, thereby providing the coordination. A 67
– AC directional overcurrent function used in a permissive overreaching transfer trip scheme
(POTT) relies on a signal from the remote end to operate and, therefore, does not require
coordination with other Protection Systems.
Instantaneous overcurrent and/or inverse time overcurrent for a 67 – AC directional
overcurrent function are utilized in a non-communication-aided Protection System for
Transmission lines. As communication is not used to prevent operation for Faults outside a
Protection System’s zone of protection, coordination is necessary with other Protection
Systems for buses, transformers, and other Transmission lines. The instantaneous overcurrent
function should be set to not overreach the end of the Transmission line. The inverse time
overcurrent function should be set to coordinate with the inverse time overcurrent function of
other Protection Systems. Changes in the magnitude of available Fault current can affect the
coordination.

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PRC-027-1 Supplemental Material
Requirement R3
The requirement states: Each Transmission Owner, Generator Owner, and Distribution Provider
shall utilize its process established in Requirement R1 to develop new and revised Protection
System settings for BES Elements.
The reliability objective of this requirement is for applicable entities to utilize the process
established in Requirement R1. Utilizing each of the elements of the process ensures a
consistent approach to the development of accurate Protection System settings, decreases the
possibility of introducing errors, and increases the likelihood of maintaining a coordinated
Protection System.

Page 14 of 17

PRC-027-1 Supplemental Material
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT adoption, the text from the rationale
text boxes will be moved to this section.
Rationale for Requirement R1:
Coordinated Protection Systems enhance reliability by isolating faulted equipment, thus
reducing the risk of BES instability or Cascading, and leaving the remainder of the BES
operational and more capable of withstanding the next Contingency. When Faults occur,
properly coordinated Protection Systems minimize the number of BES Elements that are
removed from service and protect equipment from damage. The stated purpose of this
standard is: “To maintain the coordination of Protection Systems installed to detect and isolate
Faults on Bulk Electric System (BES) Elements, such that those Protection Systems operate in
the intended sequence during Faults.” Requirement R1 captures this intent by requiring
responsible entities establish a process that, when followed, allows for their Protection Systems
to operate in the intended sequence during Faults. Requirement R1, Parts 1.1 through 1.3 are
key elements to the process for developing Protection System settings.
Part 1.1 Reviewing and updating the short-circuit model data used to develop new or revised
Protection System settings helps to assure that settings are developed using accurate, up-todate information. Generator Owners and Distribution Providers may not have or maintain
short-circuit models; consequently, these entities would obtain the short-circuit model data
from the Transmission Planners, Planning Coordinators, or Transmission Owners.
Part 1.2 A review of the developed Protection System settings reduces the likelihood of
introducing human error and verifies that the settings produced meet the technical criteria of
the entity. Peer reviews, automated checking programs, and entity-developed review
procedures are all examples of reviews.
Part 1.3 The coordination of Protection Systems associated with BES Elements that electrically
join Facilities owned by separate functional entities (Transmission Owners, Generator Owners,
and Distribution Providers) is essential to the reliability of the BES. Communication and review
of proposed settings among these entities are necessary to identify potential coordination
issues and address the issues prior to implementation of any proposed Protection System
changes.
The exclusion in PRC-001-1.1(ii), Requirement R3, R3.1 for dispersed power producing
resources applies only to interconnections between different functional entities. As such, the
exclusion only maps to Requirement R1, Part 1.3 in PRC-027-1. Due to the design of dispersed
generation sites, the Protection Systems applied on the individual dispersed generation
resources are not electrically joined Facilities owned by separate functional entities as specified
in Requirement R1, Part 1.3 nor are they connected by BES Elements. Therefore Requirement
R1, Part 1.3 does not apply to the Protection Systems applied on the individual dispersed
generation resources. Requirement R1, Part 1.3 applies only to the Protection Systems applied
on the BES Elements that electrically join Facilities owned by separate functional entities.
Unforeseen circumstances could require immediate changes to Protection System settings.
Requirement R1, Part 1.3.4 requires owners to include provisions to communicate those
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PRC-027-1 Supplemental Material
unplanned settings changes after-the-fact to the other owner(s) of the electrically joined
Facilities.
Note: In cases where a single protective relaying group performs coordination work for
separate functional entities within an organization, the communication aspects of Requirement
R1, Part 1.3 can be demonstrated by internal documentation.
Rationale for Requirement R2:
Over time, incremental changes in Fault current can accumulate enough to impact the
coordination of Protection System functions affected by Fault current. To minimize this risk,
Requirement R2 requires Transmission Owners, Generator Owners, and Distribution Providers
to periodically (1) perform Protection System Coordination Studies and/or (2) review available
Fault currents for those Protection System functions listed in Attachment A. The numerical
identifiers in Attachment A represent general protective device functions per ANSI/IEEE
Standard C37.2 Standard for Electrical Power System Device Function Numbers, Acronyms, and
Contact Designations.
Requirement R2 provides entities with options to assess the state of their Protection System
coordination.
Option 1 is a time-based methodology. The entity may choose to perform, at least once every
six-calendar years, a Protection System Coordination Study for each of its Protection Systems
identified in Attachment A. The six-calendar-year time interval was selected as a balance
between the resources required to perform the studies and the potential reliability impacts
created by incremental changes of Fault current over time.
Option 2 is a Fault current-based methodology. If Option 2 is initially selected, Fault current
baseline(s) must be established prior to the effective date of this Reliability Standard. A baseline
may be established when a new BES Element is installed or after a Protection System
Coordination Study has been performed. The baseline(s) will be used as control point(s) for
future Fault current comparisons. The Fault current baseline values can be obtained from the
short-circuit studies performed by the Transmission Planners, Planning Coordinators, or
Transmission Owners. In a time interval not to exceed six-calendar years following the effective
date of this standard, an entity must perform a Fault current comparison. If the comparison
identifies a deviation less than 15 percent, no further action is required for that six-year
interval; however, if the comparison identifies a 15 percent or greater deviation in Fault current
values (either three-phase or phase-to-ground) at each bus to which the BES Element is
connected, the entity must also perform a Protection System Coordination Study during the
same six-year interval. The baseline Fault current value(s) will be re-established whenever a
new Protection System Coordination Study is performed. Fault current changes on the System
not directly associated with BES modifications are usually small and occur gradually over time.
The accumulation of these incremental changes could affect the performance of Protection
System functions (identified in Attachment A of this standard) during Fault conditions. A Fault
current deviation threshold of 15 percent or greater (as compared to the established baseline)
and a maximum time interval of six calendar years were chosen for these evaluations. These
parameters provide an entity with latitude to choose a Fault current threshold and time interval
that best match its protection philosophy, Protection System maintenance schedule, or other
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PRC-027-1 Supplemental Material
business considerations, without creating risk to reliability (See the Supplemental Material
section for more detailed discussion).
The footnote in Option 2 describes how an entity may change from a time-based option to a
Fault current-based option for existing BES Elements as well as establishing baselines for new
BES Elements by performing Protection System Coordination Studies. The footnote also states
that Fault current baselines for BES generating resources may be established at the generator,
the generator step-up (GSU) transformer(s), or at the common point of connection at 100 kV or
above. For dispersed power producing resources, the Fault current baseline may also be
established at the BES aggregation point (total capacity greater than 75 MVA).
Option 3 provides the entity the choice of using both the time-based and Fault current-based
methodologies. For example, the entity may choose to utilize the time-based methodology for
Protection Systems at more critical Facilities and use the Fault current-based methodology for
Protection Systems at other Facilities.
Rationale for Requirement R3:
Utilizing the processes established in Requirement R1 to develop new and revised Protection
System settings provides a consistent approach to the development of Protection System
settings and will minimize the potential for errors.

Page 17 of 17

Exhibit A-2
Proposed Reliability Standard PER-006-1

PER-006-1 – Specific Training for Personnel

A. Introduction
1. Title:

Specific Training for Personnel

2. Number:

PER-006-1

3. Purpose:
To ensure that personnel are trained on specific topics essential to
reliability to perform or support Real-time operations of the Bulk Electric System.
4. Applicability:
4.1. Functional Entities:
4.1.1. Generator Operator that has:
4.1.1.1. Plant personnel who are responsible for the Real-time control of a
generator and receive Operating Instruction(s) from the Generator
Operator’s Reliability Coordinator, Balancing Authority,
Transmission Operator, or centrally located dispatch center.
5. Effective Date: See Implementation Plan for Project 2007-06.2.

B. Requirements and Measures
R1.

Each Generator Operator shall provide training to personnel identified in Applicability
section 4.1.1.1. on the operational functionality of Protection Systems and Remedial
Action Schemes (RAS) that affect the output of the generating Facility(ies) it operates.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M1. Each Generator Operator shall have available for inspection, evidence that the
applicable personnel completed training. This evidence may be documents such as
training records showing successful completion of training that includes training
materials, the name of the person, and date of training.

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

Page 1 of 7

PER-006-1 – Specific Training for Personnel

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 Generator Operator shall keep data or evidence of Requirement R1 for
the current year and three previous calendar years.

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.

Page 2 of 7

PER-006-1 – Specific Training for Personnel

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Generator Operator
failed to provide training as
described in Requirement R1
to the greater of:

The Generator Operator
failed to provide training as
described in Requirement R1
to the greater of:

The Generator Operator
failed to provide training as
described in Requirement R1
to the greater of:

The Generator Operator
failed to provide training as
described in Requirement R1
to the greater of:

•

one applicable
personnel at a single
Facility, or

•

two applicable
personnel at a single
Facility, or

•

three applicable
personnel at a single
Facility, or

•

five or more applicable
personnel at a single
Facility, or

•

5% or less of the total
applicable personnel of
the Generator Operator.

•

more than 5% and less
than or equal to 10% of
the total applicable
personnel of the
Generator Operator.

•

more than 10% and less
than or equal to 15% of
the total applicable
personnel of the
Generator Operator.

•

more than 15% of the
total applicable
personnel of the
Generator Operator.

OR
The Generator Operator
failed to provide training as
described in Requirement R1
to its applicable personnel.

Page 3 of 7

PER-006-1 – Specific Training for Personnel

D. Regional Variances
None.

E. Associated Documents
Project 2007-06.2 Implementation Plan 1

1

http://www.nerc.com/pa/Stand/Project200706_2SystemProtectionCoordinationDL/Project_2007_06_2_Imp_
Plan_Draft_1_2016_03_10_Clean.pdf
Page 4 of 7

PER-006-1 – Specific Training for Personnel

Version History
Version

Date

1

August 11, 2016

Action

Adopted by the NERC Board of
Trustees

Change Tracking

New standard developed
under Project 2007-06.2

Page 5 of 7

PER-006-1 – Supplemental Material

Guidelines and Technical Basis
Requirement R1
The Generator Operator (GOP) monitors and controls its generating Facilities in Real-time to
maintain reliability. To accomplish this, applicable plant personnel responsible for Real-time
control of a generating Facility must be trained on how the operational functionality of Protection
Systems and Remedial Action Schemes (RAS) are applied and the affects they may have on a
generating Facility. Although, training does not have to be Facility-specific, the standard applies
to plant operating personnel associated with the specific Facility to which they have Real-time
control. This does not include plant personnel not responsible for Real-time control (e.g., fuel or
coal handlers, electricians, machinists, or maintenance staff).
A periodicity for training is not specified in Requirement R1 because the GOP must ensure its
plant personnel who have Real-time control of a generator are trained. The Generator Operator
must also ensure it provides applicable training that results from changes to the operational
functionality of the Protection Systems and Remedial Action Schemes that affect the output of
the generation Facility(ies).
The phrase “operational functionality” focuses the training on how Protection Systems operate
and prevent possible damage to Elements. It also addresses how RAS detects pre-determined
BES conditions and automatically takes corrective actions.
Considerations for operational functionality may include, but are not limited to the following:
•

Purpose of protective relays and RAS

•

Zones of protection

•

Protection communication systems (e.g., line current differential, direct transfer trip, etc.)

•

Voltage and current inputs

•

Station dc supply associated with protective functions

•

Resulting actions – tripping/closing of breakers; tripping of a generator step-up (GSU)
transformer; or generator ramping/tripping control functions

Requirement R1 focuses on the operational functionality of Protection Systems and Remedial
Action Schemes specific to the generating plant and not the Bulk Electric System.
This requirement focuses on those systems that are related to the electrical output of the
generator. Protective systems which trip breakers serving station auxiliary loads (e.g., such as
pumps, fans, or fuel handling equipment) are not included in the scope of this training.
Furthermore, protection of secondary unit substation (SUS) or low voltage switchgear
transformers and relays protecting other downstream plant electrical distribution system
components are not in the scope of this training, even if a trip of these devices might eventually
result in a trip of the generating unit.
Page 6 of 7

PER-006-1 – Supplemental Material
Rationale

Rationale for Requirement R1: Protection Systems and Remedial Action Schemes (RAS) are an
integral part of reliable Bulk Electric System (BES) operation. This requirement addresses the
reliability objective of ensuring that Generator Operator (GOP) plant operating personnel
understand the operational functionality of Protection Systems and RAS and their effects on
generating Facilities.

Page 7 of 7

Exhibit A-3
Proposed Definitions

Clean Version of Proposed Definitions

Proposed Definitions
Project 2007-06 System Protection Coordination
Project 2007-06.2 Phase 2 of System Protection Coordination
Proposed Definitions
This section includes the three proposed new or modified definitions that will be included in the
Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory approval, in
accordance with the associated implementation plan.

New or Modified Term(s) for Glossary of Terms Used in NERC Reliability Standards
Protection System Coordination Study

An analysis to determine whether Protection Systems operate in the intended sequence during Faults.
Operational Planning Analysis (OPA)

An evaluation of projected system conditions to assess anticipated (pre‐Contingency) and potential
(post‐Contingency) conditions for next‐day operations. The evaluation shall reflect applicable inputs
including, but not limited to: load forecasts; generation output levels; Interchange; known Protection
System and Remedial Action Scheme status or degradation, functions, and limitations; Transmission
outages; generator outages; Facility Ratings; and identified phase angle and equipment limitations.
(Operational Planning Analysis may be provided through internal systems or through third‐party
services.)
Real‐time Assessment (RTA)

An evaluation of system conditions using Real‐time data to assess existing (pre‐Contingency) and
potential (post‐Contingency) operating conditions. The assessment shall reflect applicable inputs
including, but not limited to: load; generation output levels; known Protection System and Remedial
Action Scheme status or degradation, functions, and limitations; Transmission outages; generator
outages; Interchange; Facility Ratings; and identified phase angle and equipment limitations. (Real‐
time Assessment may be provided through internal systems or through third‐party services.)

Redline Version of Proposed Definitions

Proposed Definitions
Project 2007-06 System Protection Coordination
Project 2007-06.2 Phase 2 of System Protection Coordination
Proposed Definitions
This section includes the three proposed new or modified definitions that will be included in the
Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory approval, in
accordance with the associated implementation plan.

New or Modified Term(s) for Glossary of Terms Used in NERC Reliability Standards
Protection System Coordination Study

An analysis to determine whether Protection Systems operate in the intended sequence during Faults.
Operational Planning Analysis (OPA)

An evaluation of projected system conditions to assess anticipated (pre-‐Contingency) and potential
(post-‐Contingency) conditions for next-‐day operations. The evaluation shall reflect applicable inputs
including, but not limited to,: load forecasts; generation output levels; Interchange; known Protection
System and Special Protection SystemRemedial Action Scheme status or degradation, functions, and
limitations; Transmission outages; generator outages; Facility Ratings; and identified phase angle and
equipment limitations. (Operational Planning Analysis may be provided through internal systems or
through third-‐party services.)
Real‐time Assessment (RTA)

An evaluation of system conditions using Real-‐time data to assess existing (pre-‐Contingency) and
potential (post-‐Contingency) operating conditions. The assessment shall reflect applicable inputs
including, but not limited to: load,; generation output levels,; known Protection System and Special
Protection SystemRemedial Action Scheme status or degradation, functions, and limitations;
Transmission outages,; generator outages,; Interchange,; Facility Ratings,; and identified phase angle
and equipment limitations. (Real-‐ time Assessment may be provided through internal systems or
through third-‐party services.)