Regional Reliability Standard PRC-002-NPCC-01

Standard PRC-002-NPCC-01— Disturbance Monitoring

A. Introduction
1.

Title:

Disturbance Monitoring

2.

Number:

PRC-002-NPCC-01

3.

Purpose:

Ensure that adequate disturbance data is available to facilitate Bulk
Electric System event analyses. All references to equipment and
facilities herein unless otherwise noted will be to Bulk Electric
System (BES) elements.

4.

Applicability:
4.1. Transmission Owner
4.2. Generator Owner
4.3. Reliability Coordinator

5.

(Proposed) Effective Date: To be established.

B. Requirements
R1. Each Transmission Owner and Generator Owner shall provide Sequence of
Event (SOE) recording capability by installing Sequence of Event recorders or
as part of another device, such as a Supervisory Control And Data Acquisition
(SCADA) Remote Terminal Unit (RTU), a generator plant Digital (or
Distributed) Control System (DCS) or part of Fault recording equipment. This
capability shall: [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
1.1 Be provided at all substations and at locations where circuit breaker
operation affects continuity of service to radial Loads greater than
300MW, or the operation of which drops 50MVA Nameplate Rating or
greater of Generation, or the operation of which creates a Generation/Load
island.
Be provided at generating units above 50MVA Nameplate Rating or series
of generating units utilizing a control scheme such that the loss of 1 unit
results in a loss of greater than 50MVA Nameplate Capacity, and at
Generating Plants above 300MVA Name Plate Capacity.
1.2 Monitor the following at each location listed in 1.1:
1.2.1 Transmission and Generator circuit breaker positions
1.2.2 Protective Relay tripping for all Protection Groups that operate to
trip circuit breakers identified in 1.2.1.
1.2.3 Teleprotection keying and receive

Adopted by NERC Board of Trustees: November 4, 2010

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Standard PRC-002-NPCC-01— Disturbance Monitoring

R2. Each Transmission Owner shall provide Fault recording capability for the following Elements at facilities
where Fault recording equipment is required to be installed as per R3: [Violation Risk Factor: Medium]
[Time Horizon: Planning and Operations Planning]
2.1

All transmission lines.

2.2

Autotransformers or phase-shifters connected to busses.

2.3 Shunt capacitors, shunt reactors.
2.4 Individual generator line interconnections.
2.5 Dynamic VAR Devices.
2.6 HVDC terminals.
R3. Each Transmission Owner shall have Fault recording capability that determines the Current Zero
Time for loss of Bulk Electric System (BES) transmission Elements. [Violation Risk Factor: Medium]
[Time Horizon: Planning and Operations Planning]
R4. Each Generator Owner shall provide Fault recording capability for Generating Plants at and above 200
MVA Capacity and connected through a generator step up (GSU) transformer to a Bulk Electric
System Element unless Fault recording capability is already provided by the Transmission Owner.
[Violation Risk Factor: Medium] [Time Horizon: Planning and Operations Planning]
R5. Each Transmission Owner and Generator Owner shall record for Faults, sufficient electrical quantities
for each monitored Element to determine the following: [Violation Risk Factor: Medium] [Time
Horizon: Planning and Operations Planning]
5.1

Three phase-to-neutral voltages. (Common bus-side voltages may be used for lines.)

5.2

Three phase currents and neutral currents.

5.3

Polarizing currents and voltages, if used.

5.4

Frequency.

5.5 Real and reactive power.
R6. Each Transmission Owner and Generator Owner shall provide Fault recording with the following
capabilities: [Violation Risk Factor: Medium] [Time Horizon: Planning and Operations Planning]
6.1

Each Fault recorder record duration shall be a minimum of one (1) second.

6.2

Each Fault recorder shall have a minimum recording rate of 16 samples per

6.3

Each Fault recorder shall be set to trigger for at least the following:

cycle

6.3.1 Monitored phase overcurrents set at 1.5 pu or less of rated CT secondary current or
Protective Relay tripping for all Protection Groups.
6.3.2

Neutral (residual) overcurrent set at 0.2 pu or less of rated CT secondary current.

6.3.3 Monitored phase undervoltage set at 0.85 pu or greater.
6.4
R7.

Document additional triggers and deviations from the settings in 6.3.2 and 6.3.3 when local
conditions dictate.

Each Reliability Coordinator shall establish its area’s requirements for Dynamic Disturbance
Recording (DDR) capability that: [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]

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Standard PRC-002-NPCC-01— Disturbance Monitoring

7.1 Provides a minimum of 1 DDR per 3,000 MW of peak Load.
7.2 Records dynamic disturbance information with consideration of the following
facilities/locations:
7.2.1 Major Load centers.
7.2.2 Major Generation clusters.
7.2.3 Major voltage sensitive areas.
7.2.4 Major transmission interfaces.
7.2.5 Major transmission junctions.
7.2.6 Elements associated with Interconnection Reliability Operating Limits (IROLs).
7.2.7 Major EHV interconnections between operating areas.
R8. Each Reliability Coordinator shall specify that DDRs installed, after the approval of this standard,
function as continuous recorders. [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
R9. Each Reliability Coordinator shall specify that DDRs are installed with the following capabilities:
[Violation Risk Factor: Medium] [Time Horizon: Planning and Operations Planning]
9.1

A minimum recording time of sixty (60) seconds per trigger event.

9.2

A minimum data sample rate of 960 samples per second, and a minimum data storage rate for
RMS quantities of six (6) data points per second.

9.3

Each DDR shall be set to trigger for at least one of the following (based on manufacturers’
equipment capabilities):
9.3.1 Rate of change of Frequency.
9.3.2 Rate of change of Power.
9.3.3 Delta Frequency (recommend 20 mHz change).
9.3.4 Oscillation of Frequency.

R10. Each Reliability Coordinator shall establish requirements such that the following quantities are
monitored or derived where DDRs are installed: [Violation Risk Factor: Medium] [Time Horizon:
Planning and Operations Planning]
10.1 Line currents for most lines such that normal line maintenance activities do not interfere with
DDR functionality.
10.2 Bus voltages such that normal bus maintenance activities do not interfere with DDR
functionality.
10.3 As a minimum, one phase current per monitored Element and two phase-to-neutral voltages of
different Elements. One of the monitored voltages shall be of the same phase as the monitored
current.
10.4 Frequency.
10.5 Real and reactive power.
R11. Each Reliability Coordinator shall document additional settings and deviations from the required
trigger settings described in R9 and the required list of monitored quantities as described in R10, and
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Standard PRC-002-NPCC-01— Disturbance Monitoring

report this to the Regional Entity (RE) upon request. [Violation Risk Factor: Lower] [Time Horizon:
Operations Planning]
R12. Each Reliability Coordinator shall specify its DDR requirements including the DDR setting triggers
established in R9 to the Transmission Owners and Generator Owners. [Violation Risk Factor:
Medium] [Time Horizon: Planning and Operations Planning]
R13. Each Transmission Owner and Generator Owner that receives a request from the Reliability
Coordinator to install a DDR shall acquire and install the DDR in accordance with R12. Reliability
Coordinators, Transmission Owners, and Generator Owners shall mutually agree on an
implementation schedule. [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
R14. Each Transmission Owner and Generator Owner shall establish a maintenance and testing program for
stand alone DME (equipment whose only purpose is disturbance monitoring) that includes: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
14.1 Maintenance and testing intervals and their basis.
14.2 Summary of maintenance and testing procedures.
14.3 Monthly verification of communication channels used for accessing records remotely (if the
entity relies on remote access and the channel is not monitored to a control center staffed around
the clock, 24 hours a day, 7 days a week (24/7)).
14.4 Monthly verification of time synchronization (if the loss of time synchronization is not
monitored to a 24/7 control center).
14.5 Monthly verification of active analog quantities.
14.6 Verification of DDR and DFR settings in the software every six (6) years.
14.7 A requirement to return failed units to service within 90 days. If a DME device will be out of
service for greater than 90 days the owner shall keep a record of efforts aimed at restoring the
DME to service.
R15. Each Reliability Coordinator, Transmission Owner and Generator Owner shall share data within 30
days upon request. Each Reliability Coordinator, Transmission Owner, and Generator Owner shall
provide recorded disturbance data from DMEs within 30 days of receipt of the request in each of the
following cases: [Violation Risk Factor: Lower] [Time Horizon: Operations]
15.1 NERC, Regional Entity, Reliability Coordinator.
15.2 Request from other Transmission Owners, Generator Owners within NPCC.
R16. Each Reliability Coordinator, Transmission Owner and Generator Owner shall submit the data files
conforming to the following format requirements: [Violation Risk Factor: Lower] [Time Horizon:
Operations]
16.1 The data files shall be capable of being viewed, read, and analyzed with a generic COMTRADE
analysis tool as per the latest revision of IEEE Standard C37.111.
16.2 Disturbance Data files shall be named in conformance with the latest revision of IEEE Standard
C37.232.
16.3 Fault Recorder and DDR Files shall contain all monitored channels. SOE records shall contain
station name, date, time resolved to milliseconds, SOE point name, status.

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Standard PRC-002-NPCC-01— Disturbance Monitoring

R17. Each Reliability Coordinator, Transmission Owner and Generator Owner shall maintain, record and
provide to the Regional Entity (RE), upon request, the following data on the DMEs installed to meet
this standard: [Violation Risk Factor: Lower] [Time Horizon: Operations]
17.1 Type of DME.
17.2 Make and model of equipment.
17.3 Installation location.
17.4 Operational Status.
17.5 Date last tested.
17.6 Monitored Elements.
17.7 All identified channels.
17.8 Monitored electrical quantities.

C. Measures
M1. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
provided Sequence of Event recording capability in accordance with 1.1 and 1.2. (R1)
M2. Each Transmission Owner shall have, and provide upon request, evidence that it provided Fault
recording capability in accordance with 2.1 to 2.6. (R2)
M3. Each Transmission Owner shall have, and provide upon request, evidence that it provided Fault
recording capability that determined the Current Zero Time for loss of Bulk Electric System (BES)
transmission Elements in accordance with R3.
M4. Each Generator Owner shall have, and provide upon request, evidence that it provided Fault recording
capability for its Generating Plants at and above 200 MVA Capacity in accordance with R4.
M5. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
records for Faults, sufficient electrical quantities for each monitored Element to determine the
parameters listed in 5.1 to 5.5. (R5)
M6. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
provided Fault recording capability in accordance with 6.1 to 6.4. (R6)
M7. Each Reliability Coordinator shall have, and provide upon request, evidence that it established its
area’s requirements for Dynamic Disturbance Recording (DDR) capability in accordance with 7.1 and
.2. (R7)
M8. Each Reliability Coordinator shall have, and provide upon request, evidence that DDRs installed after
the approval of this standard function as continuous recorders. (R8)
M9. Each Reliability Coordinator shall have, and provide upon request, evidence that it developed DDR
setting triggers to include the parameters listed in 9.1 to 9.3. (R9)
M10. Each Reliability Coordinator shall have, and provide upon request, evidence that DDRs monitor the
Elements listed in 10.1 through 10.5. (R10)
M11. Each Reliability Coordinator shall have, and provide upon request, evidence that it documented
additional settings and deviations from the required trigger settings described in R9 and the required
list of monitored quantities as described in R10. (R11)
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Standard PRC-002-NPCC-01— Disturbance Monitoring

M12. Each Reliability Coordinator shall have, and provide upon request, evidence that it specified its DDR
requirements which included the DDR setting triggers established in R9 to the Transmission Owners
and Generator Owners in the Reliability Coordinator’s area. (R12)
M13. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that
it acquired and installed the DDRs in accordance with the specifications contained in the Reliability
Coordinator’s request, and a mutually agreed upon implementation schedule. (R13)
M14. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
has a maintenance and testing program for stand alone DME
(equipment whose only purpose is disturbance monitoring) that meets the requirements in 14.1
through 14.7. (R14)
M15. Each Reliability Coordinator, Transmission Owner and Generator Owner shall have, and provide
upon request, evidence that it provided recorded disturbance data from DMEs within 30 days of the
receipt of the request from the entities listed in 15.1 and 15.2. (R15)
M16. Each Reliability Coordinator, Transmission Owner and Generator Owner shall have, and provide
upon request, evidence that it submitted the data files in a format that meets the requirements in 16.1
through 16.3. (R16)
M17. Each Reliability Coordinator, Transmission Owner and Generator Owner shall have, and provide
upon request, evidence that it maintained a record of and provided to NPCC when requested, the data
on DMEs installed meeting the requirements 17.1 through 17.8. (R17)
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
NPCC Compliance Committee
1.2. Compliance Monitoring Period and Reset Time Frame
Not Applicable
1.3. Data Retention
The Transmission Owner and Generator Owner shall keep evidences for three calendar years for
Measures 1, 5, 6, 13, 16 and 17.
The Transmission Owner shall keep evidence for three years for Measures 2 and 3.
The Generator Owner shall keep evidence for three years for Measure 4.
The Reliability Coordinator shall keep evidence for three years for Measures 7, 8, 9, 10, 11, 12,
16 and 17.
The Transmission Owner and Generator Owner shall keep evidences for twenty-four calendar
months for Measures 14 and 15.
The Reliability Coordinator shall keep evidence for twenty-four calendar months for Measure
15.

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Standard PRC-002-NPCC-01— Disturbance Monitoring

If a Transmission Owner, Generator Owner or Reliability Coordinator is found non-compliant, it
shall keep information related to the non-compliance until found compliant.

The Compliance Enforcement Authority shall keep the last audit and all subsequent record.
1.4. Compliance Monitoring and Assessment Processes
-

Self-Certifications
Spot Checking
Compliance Audits
Self-Reporting
Compliance Violation Investigations
Complaints

1.5. Additional Compliance Information
None
2.

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R1
The Transmission
Owner or
Generator Owner
provided the
Sequence of
Event recording
capability
meeting the bulk
of R1 but
missed…

Up to and
including 10%
of the total set,
which is the
product of the
total number of
locations in 1.1
times the total
number of
parameters in
1.2.

More than 10% and
up to and including
20% of the total set,
which is the product
of the total number
of locations in 1.1
times the total
number of
parameters in 1.2.

More than 20% and
up to and including
30% of the total set,
which is the product
of the total number
of locations in 1.1
times the total
number of
parameters in 1.2.

More than 30% of the
total set, which is the
product of the total
number of locations in
1.1 times the total
number of parameters in
1.2.

R2
The Transmission
Owner provided
the Fault
recording
capability
meeting the bulk
of R2 but
missed…

Up to and
including 10%
of the total set,
which is the
total number of
Elements at all
locations
required to be
installed as per
R3 that meet
the criteria
listed in 2.1
through 2.6.

More than 10% and
up to and including
20% of the total set,
which is the total
number of Elements
at all locations
required to be
installed as per R3
that meet the criteria
listed in 2.1 through
2.6.

More than 20% and
up to and including
30% of the total set,
which is the total
number of
Elements at all
locations required
to be installed as
per R3 that meet
the criteria listed in
2.1 through 2.6.

More than 30% of the
total set, which is the
total number of Elements
at all locations required
to be installed as per R3
that meet the criteria
listed in 2.1 through 2.6.

Not applicable.

Not applicable.

Fault recording capability
that determines the

R3
Not applicable.
The Transmission

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Standard PRC-002-NPCC-01— Disturbance Monitoring
Owner failed to
provide…

current zero time for loss
of transmission Elements.

Up to and
including 10%
of its
Generating
Plants at and
above 200
MVA Capacity
and connected
to a Bulk
Electric System
Element if
Fault recording
capability for
that portion of
the system is
inadequate.
R5
Up to and
The Transmission including 10%
Owner or
of the total set
Generator Owner of parameters,
failed to record
which is the
for the Faults… product of the
total number of
monitored
Elements and
the number of
parameters
listed in 5.1
through 5.5.

More than 10% and
up to and including
20% of its
Generating Plants at
and above 200 MVA
Capacity and
connected to a Bulk
Electric System
Element if Fault
recording capability
for that portion of
the system is
inadequate.

More than 20% and
up to 30% of its
Generating Plants at
and above 200 MVA
Capacity and
connected to a Bulk
Electric System
Element if Fault
recording capability
for that portion of
the system is
inadequate.

More than 30% of its
Generating Plants at and
above 200 MVA
Capacity and connected
to a Bulk Electric System
Element if Fault
recording capability for
that portion of the system
is inadequate.

More than 10% and
up to and including
20% of the total set
of parameters, which
is the product of the
total number of
monitored Elements
and the number of
parameters listed in
5.1 through 5.5.

More than 20% and
up to and including
30% of the total set
of parameters, which
is the product of the
total number of
monitored Elements
and the number of
parameters listed in
5.1 through 5.5.

More than 30% of the
total set of parameters,
which is the product of
the total number of
monitored Elements and
the number of parameters
listed in 5.1 through 5.5.

R6
The Transmission
Owner or
Generator Owner
failed …

To provide Fault
recording capability
for more than 10%
and up to and
including 20% of the
total set of
requirements, which
is the product of the
total number of
monitored Elements
and the total number
of capabilities
identified in 6.1
through 6.2.
OR
Failed to document
additional triggers or

To provide Fault
recording capability
for more than 20%
and up to and
including 30% of the
total set of
requirements, which
is the product of the
total number of
monitored Elements
and the total number
of 6.1 through 6.2.
OR
Failed to document
additional triggers or
deviations from the
settings stipulated in

To provide Fault
recording capability for
more than 30% of the
total set of requirements,
which is the product of
the total number of
monitored Elements and
the total number of
capabilities identified in
6.1 through 6.2.
OR
Failed to document
additional triggers or
deviations from the
settings stipulated in 6.3
through 6.4 for more than
ten (10) locations.

R4
The Generator
Owner failed to
provide Fault
recording
capability at…

To provide
Fault recording
capability for
up to and
including 10%
of the total set
of
requirements,
which is the
product of the
total number of
monitored
Elements and
the total
number of
capabilities
identified in 6.1

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Standard PRC-002-NPCC-01— Disturbance Monitoring
deviations from the
through 6.2.
settings stipulated in
OR
6.3 through 6.4 for
Failed to
more than two (2)
document
and up to and
additional
including five (5)
triggers or
deviations from locations.
the settings
stipulated in 6.3
through 6.4 for
up to 2
locations.
More than 10% and
R7
Up to and
up to and including
The Reliability
including 10%
20% of the required
Coordinator
of the required
failed to establish DDR coverage DDR coverage for
its area as per 7.1
its area’s
for its area as
requirements
per 7.1and 7.2. and 7.2.
for…
R8
Not applicable. Not applicable.
The Reliability
Coordinator failed
to specify
that DDRs
installed…

R9
Not
The Reliability
applicable.
Coordinator failed
to specify that
DDRs are
installed
without…
R10
Not applicable.
The Reliability
Coordinator failed
to ensure that the
quantities listed in 10.1 through 10.5
are monitored or
derived…
Up to two (2)
R11
facilities within
The Reliability
Coordinator failed the Reliability
to document and Coordinator’s
area that have a
report to the
Regional Entity DDR.
upon request
additional settings and deviations
from the required
trigger settings
described in R9

6.3 through 6.4 for
more than five (5)
and up to and
including ten (10)
locations.

More than 20% and
up to and including
30% of the required
DDR coverage for
its area as per 7.1
and 7.2.

More than 30% of the
required DDR coverage
for its area as per 7.1 and
7.2.

Not applicable.

Function as continuous
recorders.

Not applicable.

Not applicable.

The capabilities listed in
9.1 through 9.3.

Not applicable.

Not applicable.

Where DDRs are
installed.

More than two (2)
and up to five (5)
facilities within the
Reliability
Coordinator’s area
that have a DDR.

More than five (5)
and up to ten (10)
facilities within the
Reliability
Coordinator’s area
that have a DDR.

More than ten (10)
facilities within the
Reliability Coordinator’s
area that have a DDR.

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Standard PRC-002-NPCC-01— Disturbance Monitoring
and the required
list of monitored
quantities as
described in R10
for…

R12
Not applicable.
The Reliability
Coordinator failed
to specify to the
Transmission
Owners and
Generator Owners
its DDR
requirements
including the DDR setting
triggers
established in R9
but missed…
R13
Up to and
The Transmission including 10%
Owner or
of the
Generator Owner requirement set
failed to comply of the
with the
Reliability
Reliability
Coordinator’s
Coordinator’s
request to
request installing install DDRs,
the DDR in
with the
accordance with requirement set
R12 for…
being the total
number of
DDRs
requested times
the number of
setting triggers
specified for
each DDR.
R14
Established a
The Transmission maintenance
Owner or
and testing
Generator
program for
Owner…
stand alone
DME but
provided
incomplete data
for any one (1)
of 14.1 through

Not applicable.

Not applicable.

Established setting
triggers.

More than 10% and
up to 20% of the
requirement set
requested by the
Reliability
Coordinator for
installing DDRs,
with the requirement
set being the total
number of DDRs
requested times the
number of setting
triggers specified for
each DDR.

More than 20% and
up to 30% of the
requirement set
requested by the
Reliability
Coordinator for
installing DDRs,
with the requirement
set being the total
number of DDRs
requested times the
number of setting
triggers specified for
each DDR.

More than 30% of the
requirement set requested
by the Reliability
Coordinator and
installing DDRs, with the
requirement set being the
total number of DDRs
requested times the
number of setting triggers
specified for each DDR
OR
The Reliability
Coordinator,
Transmission Owners,
and Generator Owners
failed to mutually agree
on an implementation
schedule.

Established a
maintenance and
testing program for
stand alone DME
but provided
incomplete data for
more than one (1)
and up to and
including three (3)
of 14.1 through 14.7.

Established a
maintenance and
testing program for
stand alone DME
but provided
incomplete data for
more than three (3)
and up to and
including six (6) of
14.1 through 14.7.

Did not establish any
maintenance and testing
program for DME;
OR
The Transmission Owner
or Generator Owner
established a
maintenance and testing
program for DME but did
not provide any data that

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Standard PRC-002-NPCC-01— Disturbance Monitoring
14.7.

R15
The Reliability
Coordinator,
Transmission
Owner or
Generator Owner
provided recorded
disturbance data
from DMEs but
was late for…
R16
The Reliability
Coordinator,
Transmission
Owner or
Generator Owner
failed to submit…

R17
The Reliability
Coordinator,
Transmission
Owner or
Generator Owner
failed to maintain
or provide to
the Regional
Entity , upon
request…

meets all of 14.1 through
14.7.

Up to and
including
fifteen (15)
days in meeting
the requests of
an entity, or
entities in 15.1,
or 15.2.

More than fifteen
(15) days but less
than and including
thirty (30) days in
meeting the requests
of an entity, or
entities in 15.1 or
15.2.

More than 30 days
but less than and
including forty-five
(45) days in meeting
the requests of an
entity, or entities in
15.1 or 15.2.

More than forty-five (45)
days in meeting the
requests of an entity, or
entities in 15.1 or 15.2.

Up to and
including two
(2) data files in
a format that
meets the
applicable
format
requirements in
16.1 through
16.3.
Up to and
including two
(2) of the items
in 17.1 through
17.8.

More than two (2)
and up to and
including five (5)
data files in a format
that meets the
applicable format
requirements in 16.1
through 16.3.

More than five (5)
and up to and
including ten (10)
data files in a format
that meets the
applicable format
requirements in 16.1
through 16.3.

More than ten (10) data
files in a format that
meets the applicable
format requirements in
16.1 through 16.3.

More than two (2)
and up to and
including four (4) of
the items in 17.1 to
17.8.

More than four (4)
and up to and
including six (6) of
the items in 17.1
through 17.8.

More than six (6) of the
items in 17.1 through
17.8.

E. Associated Documents

Version History 
Version

Date

Action

Change Tracking

1

November 4,
2010

Adopted by NERC Board of Trustees

New

1

October 20,
2011

FERC Order issued approving PRC002-NPCC-01 (FERC’s Order became
effective on October 20, 2011)

Adopted by NERC Board of Trustees: November 4, 2010

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