[Federal Register: May 28, 2009 (Volume 74, Number 101)]
[Proposed Rules]
[Page 25461-25478]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr28my09-22]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM08-13-000]
Transmission Relay Loadability Reliability Standard
May 21, 2009.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Notice of proposed rulemaking.
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SUMMARY: Pursuant to section 215 of the Federal Power Act, the Federal
Energy Regulatory Commission proposes to approve Reliability Standard
PRC-023-1 (Transmission Relay Loadability Reliability Standard)
developed by the North American Electric Reliability Corporation. The
proposed Reliability Standard requires certain transmission owners,
generator owners, and distribution providers to set protective relays
according to specific criteria in order to ensure that the relays
reliably detect and protect the electric network from all fault
conditions, but do not limit transmission loadability or interfere with
system operators' ability to protect system reliability. While all
relays detect and protect the electric network from fault conditions,
the proposed Reliability Standard applies only to load-responsive phase
protection relays. In addition, pursuant to section 215(d)(5) of the
Federal Power Act, the Commission proposes to direct NERC to develop
modifications to the proposed Reliability Standard to address specific
concerns identified by the Commission.
DATES: Comments are due July 27, 2009.
ADDRESSES: Interested persons may submit comments, identified by Docket
[[Page 25462]]
No. RM08-13-000, by any of the following methods:
Agency Web Site: http://www.ferc.gov. Documents created
electronically using word processing software should be filed in native
applications or print-to-PDF format and not in a scanned format.
Mail/Hand Delivery. Commenters unable to file comments
electronically must mail or hand deliver an original and 14 copies of
their comments to: Federal Energy Regulatory Commission, Secretary of
the Commission, 888 First Street, NE., Washington, DC 20426.
FOR FURTHER INFORMATION CONTACT:
Joshua Konecni (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-6291.
Michael Henry (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8532.
Cynthia Pointer (Technical Information), Office of Electric
Reliability, Division of Reliability Standards, Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202) 502-6069.
Robert Snow (Technical Information), Office of Electric Reliability,
Division of Reliability Standards, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
6716.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Background............................................... 2
A. Protective Relays.................................... 2
B. Protective Relays and the August 14, 2003 Blackout... 10
C. Task Force Final Blackout Report..................... 11
D. NERC and Task Force Recommendations.................. 12
II. Proposed Reliability Standard PRC-023-1................. 15
A. Requirements......................................... 18
1. Requirement R1................................... 19
2. Requirement R2................................... 23
3. Requirement R3................................... 24
B. Interactions With Other Standards.................... 25
C. Effective Date....................................... 26
III. Discussion............................................. 28
A. Legal Standard....................................... 28
B. Decision............................................. 30
C. Applicability........................................ 35
1. Applicability to Entities With Facilities 36
Operated Between 100 kV and 200 kV and to
Facilities Operated Below 100 kV That Are Critical
to the Reliability of the Bulk Electric System.....
2. Generator Step-Up and Auxiliary Transformers..... 46
D. Need to Address Additional Issues.................... 49
1. Zone 3/Zone 2 Relays Applied as Remote Circuit 50
Breaker Failure and Backup Protection..............
2. Protective Relays Operating Unnecessarily Due to 54
Stable Power Swings................................
E. Concerns With the Implementation of Certain Criteria 61
Under Requirement R1...................................
1. Requirement R1.2................................. 63
2. Requirement R1.10................................ 66
3. Requirement R1.12................................ 70
F. Requirement R3 and Its Sub-Requirements.............. 74
G. Attachment A......................................... 76
1. Section (2): Evaluation of Out-of-Step Blocking 77
Schemes............................................
2. Section (3): List of Protection Systems Excluded 78
From the Standard..................................
H. Effective Date....................................... 82
I. Violation Risk Factors............................... 87
1. Requirement R1and Its Sub-Requirements........... 91
2. Requirement R3................................... 93
J. Violation Severity Levels............................ 95
1. Requirement R1................................... 99
2. Requirement R2................................... 102
3. Requirement R3................................... 105
IV. Information Collection Statement........................ 109
V. Environmental Analysis................................... 115
VI. Regulatory Flexibility Act Analysis..................... 116
VII. Comment Procedures..................................... 119
VIII. Document Availability................................. 123
1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Federal Energy Regulatory Commission (Commission) proposes to approve
Reliability Standard PRC-023-1 (Transmission Relay Loadability
Reliability Standard), developed by the North American Electric
Reliability Corporation (NERC) in its capacity as the Electric
Reliability Organization (ERO).\2\ The proposed Reliability Standard
requires certain transmission owners, generator owners, and
distribution providers to set protective relays according to specific
criteria in order to ensure that the relays reliably detect and protect
the electric network
[[Page 25463]]
from all fault conditions, but do not limit transmission loadability
\3\ or interfere with system operators' ability to protect system
reliability.\4\ In addition, pursuant to section 215(d)(5) of the
FPA,\5\ the Commission proposes to direct the ERO to develop
modifications to the proposed Reliability Standard to address specific
concerns identified by the Commission.
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\1\ 16 U.S.C. 824o.
\2\ Section 215(e)(3) of the FPA directs the Commission to
certify an ERO to develop mandatory and enforceable Reliability
Standards, subject to Commission review and approval. 16 U.S.C.
824o(e)(3). Following a selection process, the Commission selected
and certified NERC as the ERO. North American Electric Reliability
Corp., 116 FERC ] 61,062 (ERO Certification Order), order on reh'g &
compliance, 117 FERC ] 61,126 (ERO Rehearing Order) (2006), aff'd
sub nom. Alcoa, Inc. v. FERC, No. 06-1426, 2009 U.S. App. LEXIS 9905
(D.C. Cir. May 8, 2009).
\3\ In the context of the proposed Reliability Standard,
``loadability'' refers to the ability of protective relays to
refrain from operating under load conditions.
\4\ The Commission is not proposing any new or modified text to
its regulations. Rather, as provided in 18 CFR part 40, a proposed
Reliability Standard will not become effective until approved by the
Commission, and the ERO must post on its website each effective
Reliability Standard.
\5\ 16 U.S.C. 824(d)(5).
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I. Background
A. Protective Relays
2. Protection systems are used to detect, operate, and initiate the
removal of faults on an electric system.\6\ Some protection systems use
redundancy, measurements, and telecommunications facilities to
accurately identify and confirm the location of a fault; \7\ others use
a single system that relies only on local information.\8\
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\6\ A ``fault'' is defined in the NERC Glossary of Terms used in
Reliability Standards as, ``[a]n event occurring on an electric
system such as a short circuit, a broken wire, or an intermittent
connection.''
\7\ ``Redundancy'' means that the primary component has a
``twin'' component that operates to isolate the fault in the same
manner at approximately the same time. The transmission planner may
assume that, at any given time, either the primary component or its
redundant component will be operable and therefore the system will
clear the contingency in the time associated with the primary
protection.
\8\ ``Local information'' refers to system measurements obtained
at the immediate location of the protective relay. Achieving
protection coordination and performance are required in the present
Reliability Standards. Special protection systems and redundancy are
not required as long as the applied system can achieve the desired
performance.
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3. Protective relays, also known as primary relays, are one type of
equipment used in protection systems.\9\ Protective relays read
electrical measurements (such as current, voltage, and frequency) and
remove from service any system element that suffers a fault and
threatens to damage equipment or interfere with effective operation of
the system.\10\ Protective relays are applied to protect specific
system elements and are set to recognize certain electrical
measurements as indicating a fault. When a protective relay detects a
fault, it sends a signal to an interrupting device (such as a circuit
breaker) \11\ to disconnect the element or elements from the rest of
the system.
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\9\ By definition, protection systems include protective relays,
associated communication systems, voltage and current sensing
devices, station batteries, and DC control circuitry. See NERC
Glossary of Terms Used in Reliability Standards.
\10\ There are two generic types of protective relays: those
that have fixed characteristics (i.e., those that are used similar
to a control switch, such as lockout relays) and those whose
characteristic can be set to vary (i.e., those that are used to
detect faults). The proposed Reliability Standard is applicable to
the latter type of protective relay.
\11\ A ``circuit breaker'' is a power operated switch capable of
interrupting current (e.g., load, fault, etc.) that is within its
rating.
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4. The sequence in which protective relays operate is important.
For example, on a transmission line, coordination of protection through
distance settings and time delays ensures that the relay closest to a
fault can operate before a relay farther away from the fault.\12\ If
the more distant relay operates first, it will disconnect both the
transmission equipment necessary to remove the fault and ``healthy''
equipment that should remain in service.
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\12\ ``Coordination of protection'' is defined by the Institute
of Electrical and Electronics Engineers (IEEE) Std. C37.113-1999,
``IEEE Guide for Protective Relay Applications to Transmission
Lines'' as ``[t]he process of choosing settings or time delay
characteristics of protective devices, such that operation of the
devices will occur in a specified order to minimize customer service
interruption and power system isolation due to a power system
disturbance.''
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5. Impedance relays are the most common type of relays used to
protect transmission lines. Impedance relays continuously measure local
voltage and current on the protected transmission line and operate when
the measured magnitude and phase of the impedance (voltage/current)
falls within the settings or reach of the relay.\13\ Impedance relays
can also provide backup protection and protection against remote
circuit breaker failure.
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\13\ The ``reach'' of the relay refers to the length of the
transmission line for which the relay is set to protect and is
generally used in reference to impedance relays. Proposed
Reliability Standard PRC-023-1 establishes criteria to be used for
setting phase impedance, as well as, overcurrent relays dependent on
the system configuration where the relay is applied. The system
configurations are described in sub-Requirements R1.1 through R1.13.
Further, as impedance relays, also known as distance relays, detect
changes in currents (I*) and voltages (V*) to determine the apparent
impedance (Z*) according to the relationship of Z* = V*/I* of the
line, impedance are directionally sensitive. They are forward
looking into the lines that they are protecting, i.e., they protect
against faults in front of and not behind the relay's installed
location.
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6. Multiple impedance relays are installed at each end of the
transmission line \14\ with each typically used to protect a certain
percentage, or zone, of the local transmission line and remote lines.
The purpose of zonal protection is to protect each part of the local
and remote transmission lines (i.e., no ``gaps'') and to disconnect
only the equipment necessary to remove a fault even if the closest
protection system does not operate as desired. Impedance relays may be
set to cover one, two, or three protection zones (zone 1, zone 2, and
zone 3 respectively), with appropriate time delays to achieve
coordination of protection.
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\14\ Impedance relays are installed at each end of a
transmission line and protect it in the forward looking direction of
the relay, i.e., the impedance relays at the opposite terminals of a
line ``look'' toward each other to detect line faults that are
within their respective reaches and directions.
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7. Zone 1 relays are typically set to reach 80 percent of the
protected transmission line. They leave a 20 percent margin at the far
end of the line to avoid operating for faults for which they are not
intended to operate, such as for faults on an adjacent line.\15\ Zone 1
relays provide fast primary protection and so are set to operate
without an intentional time delay.
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\15\ The margin takes into account measurement errors of the
relay, imprecise line impedance used in the relay setting
calculation, and changes in system conditions.
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8. Zone 2 relays provide backup protection and are typically set to
reach 125 percent of the protected transmission line, i.e., 100 percent
of the protected transmission line and 25 percent of the adjacent
transmission line (i.e., they have a 25 percent margin). Because zone 2
relays can operate for faults on both the protected transmission line
and on parts of adjacent transmission lines connected to the remote
terminal,\16\ they are set with a time delay to allow for coordination
of protection with the zone 1 relay on the faulted line. This time
delay is determined or verified through system planning analysis.\17\
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\16\ For example, a zone 2 relay will operate if the impedance
on the adjacent line and the impedance of the protected line fall
within the relay's setting.
\17\ System planning analysis would identify the performance,
required by Table 1 of the Transmission Planning (TPL) Reliability
Standards.
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9. Zone 3 relays provide remote circuit breaker failure and backup
protection (i.e., when the remote circuit breaker fails to open to
remove a fault) for remote distance faults on a transmission line; they
amount to a backup of the zone 2 backup.\18\ Zone 3 relays and zone 2
relays set to operate like zone 3 relays (zone 3/zone 2 relays) are
typically set to reach 100 percent of the protected transmission line
with a margin of more than 100 percent of the longest line (including
any series elements such as transformers) that emanates from the remote
buses. To ensure coordination of protection, zone
[[Page 25464]]
3/zone 2 relays are set with a longer time delay than zone 2 relays.
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\18\ James S. Thorp, Power Systems Engineering Research Center,
The Protection System in Bulk Power Networks 5 (2003).
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B. Protective Relays and the August 14, 2003 Blackout
10. On August 14, 2003, a blackout that began in Ohio affected
significant portions of the Midwest and Northeast United States, and
Ontario, Canada (2003 blackout). This blackout affected an area with an
estimated 50 million people and 61,800 megawatts of electric load.\19\
The subsequent investigation and report completed by the U.S.-Canada
Power System Outage Task Force (Task Force) concluded that a
substantial number of lines disconnected when backup distance and phase
relays operated under non-fault conditions. The Task Force determined
that the unnecessary operation of these relays contributed to cascading
outages at the start of the blackout and accelerated the geographic
spread of the cascade.\20\ Seeking to prevent or minimize the scope of
future blackouts, both the Task Force and NERC made recommendations to
ensure that protective relays do not contribute to future blackouts.
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\19\ U.S.-Canada Power System Outage Task Force, Final Report on
the August 14, 2003 Blackout in the United States and Canada: Causes
and Recommendations, (April 2004) (Final Blackout Report), available
at http://www.ferc.gov/industries/electric/indus-act/blackout.asp.
\20\ Id. at 80.
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C. Task Force Final Blackout Report
11. The Task Force determined that one of the principal reasons why
cascading outages spread beyond Ohio was the operation of zone 3/zone 2
relays in response to overloads rather than true faults.\21\ The Task
Force identified fourteen 345 kV and 138 kV transmission lines that
disconnected because of zone 3/zone 2 relays applied as remote circuit
breaker failure and backup protection. Among these relays were several
zone 2 relays in Michigan that were set to overreach their protected
lines by more than 200 percent without any intentional time delay.\22\
The Task Force stated that although these and the other relays operated
according to their settings, they operated so quickly that they impeded
the natural ability of the electric system to hold together and did not
allow time for operators to try to stop the cascade.\23\ The Task Force
described the unnecessary operation of these relays as the ``common
mode of failure that accelerated the geographic spread of the
cascade.'' \24\ The Task Force also indicated that as the cascade
progressed beyond Ohio it spread because of dynamic power swings and
the resulting instability.\25\
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\21\ Id. at 73.
\22\ Id. at 80.
\23\ Id.
\24\ Id.
\25\ Id. at 81.
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D. NERC and Task Force Recommendations
12. NERC conducted its own investigation into the 2003 blackout and
developed recommendations to prevent and mitigate future cascades.
Recommendation 8A of the NERC Report addresses the need to evaluate
zone 3 relays to determine whether they will operate under extreme
emergency conditions:
All transmission owners shall, no later than September 30, 2004,
evaluate the zone 3 relay settings on all transmission lines
operating at 230 kV and above for the purpose of verifying that each
zone 3 relay is not set to trip on load under extreme emergency
conditions[]. In each case that a zone 3 relay is set so as to trip
on load under extreme conditions, the transmission operator shall
reset, upgrade, replace, or otherwise mitigate the overreach of
those relays as soon as possible and on a priority basis, but no
later than December 31, 2005. Upon completing analysis of its
application of zone 3 relays, each transmission owner may no later
than December 31, 2004 submit justification to NERC for applying
zone 3 relays outside of these recommended parameters. The Planning
Committee shall review such exceptions to ensure they do not
increase the risk of widening a cascading failure of the power
system.\26\
\26\ August 14, 2003 Blackout: NERC Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts 13 (2004) (NERC
Report).
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13. In Recommendation No. 21A of the Final Blackout Report, the
Task Force recommended that NERC go further than it had proposed in its
report:
NERC [should] broaden the review [described in Recommendation 8A
of the NERC Report] to include operationally significant 115 kV and
138 kV lines, e.g., lines that are part of monitored flowgates or
interfaces. Transmission owners should also look for zone 2 relays
set to operate like zone 3 [relays].\27\
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\27\ Final Blackout Report at 158.
14. NERC states that PRC-023-1 responds to these recommendations.
II. Proposed Reliability Standard PRC-023-1
15. Reliability Standard PRC-023-1 requires certain transmission
owners, generator owners, and distribution providers to set certain
protective relays according to specific criteria to ensure that they
detect only faults for which they must operate and do not operate
unnecessarily during non-fault load conditions. NERC proposes that PRC-
023-1 apply to transmission owners, generator owners, and distribution
providers with load-responsive phase protection systems as described in
Attachment A to PRC-023-1, applied to: (1) All transmission lines and
transformers with low-voltage terminals operated or connected at 200 kV
and above; and (2) those transmission lines and transformers with low-
voltage terminals operated or connected between 100 kV and 200 kV that
are designated by planning coordinators as critical to the reliability
of the bulk electric system. The proposed Reliability Standard also
prescribes the settings that should be used when it is appropriate to
use a 0.85 per unit voltage and a power factor angle of 30 degrees.
NERC states that PRC-023-1 has a broader application than the
recommendations in the NERC and Task Force final reports, which address
only zone 3/zone 2 relays, because other load-responsive relays were
found to have contributed to the 2003 blackout.
16. Under the proposed Reliability Standard, protective relay
settings must provide essential facility protection for faults without
preventing operation of the Bulk-Power System in accordance with
established Facility Ratings.\28\ If essential facility protection
imposes a more constraining limit on the system, PRC-023-1 requires
that the Facility Rating reflect that limit. Proposed Reliability
Standard PRC-023-1 applies to any protective functions that could
operate with or without time delay, on load current, including but not
limited to: Phase distance, out-of-step tripping, switch-on-to-fault,
overcurrent relays, and communication-aided protection applications. It
also requires evaluation of out-of-step blocking schemes \29\ to ensure
that they do not operate for faults during specified loading
conditions.\30\
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\28\ As defined in NERC's Glossary of Terms Used in Reliability
Standards.
\29\ ``Out-of-step blocking'' refers to a protection system that
is capable distinguishing between a fault and a power swing. If a
power swing is detected, the protection system, ``blocks,'' or
prevents the tripping of its associated transmission facilities.
\30\ See PRC-023-1 Attachment A, Item 1.
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17. The proposed Reliability Standard expressly excludes from its
requirements: Relay elements enabled only when other relays or
associated systems fail (e.g., overcurrent elements enabled only during
abnormal system conditions or a loss of communications), protection
relay systems intended for the detection of ground fault conditions or
for protection during stable power swings, generator protective relays
[[Page 25465]]
susceptible to load, relay elements used only for special protection
systems applied and approved in accordance with NERC Reliability
Standards PRC-012 through PRC-017,\31\ protection relay systems
designed to respond only in time periods that allow operators 15
minutes or longer to respond to overload conditions, thermal emulation
relays used in conjunction with dynamic Facility Ratings, relay
elements associated with DC lines, and relay elements associated with
DC converter transformers.
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\31\ The Commission has approved PRC-015-0, PRC-016-0, and PRC-
017-0 and has not approved or remanded PRC-012-0, PRC-013-0, and
PRC-014-0.
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A. Requirements
18. Proposed Reliability Standard PRC-023-1 consists of three
compliance requirements.\32\ Requirements R1 and R2 apply to
transmission owners, generator owners, and distribution providers with
transmission lines or transformers with low-voltage terminals connected
at 200 kV and above. Requirement R3 requires planning coordinators to
identify the facilities operated between 100 kV and 200 kV that are
critical to the reliability of the bulk electric system, and therefore
subject to Requirement R1.
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\32\ NERC has also filed a document entitled: ``PRC-023
Reference--Determination and Application of Practical Relaying
Loadability Ratings.'' NERC states that this document explains the
rationale behind the requirements in the proposed Reliability
Standard and provides the calculation methodology to help entities
comply. NERC states that the reference document is presented for
information only and does not request that the Commission take
action on it.
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1. Requirement R1
19. Requirement R1 states that each transmission owner, generator
owner, and distribution provider subject to the proposed Reliability
Standard shall use one of the criteria prescribed in sub-Requirements
R1.1 through R1.13 for any specific circuit terminal to prevent its
phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the bulk electric
system for all fault conditions.\33\
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\33\ Requirement R1 also requires each transmission owner,
generator owner, and distribution provider to evaluate relay
loadability at 0.85 per unit voltage and a power factor angle of 30
degrees.
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20. Sub-Requirements R1.1 through R1.13 prescribe specific criteria
to be used for certain transmission system configurations. These
criteria account for the presence of devices such as series capacitors
and address circuit and transformer thermal capability. NERC states
that the criteria set forth in the sub-requirements reflect the maximum
circuit loading for various system configurations and allow the
protective relays subject to the proposed Reliability Standard to be
set for optimum protection while carrying that load. NERC claims that
each criterion balances the need to protect the system with the
optimization of load carrying capability.
21. Sub-Requirement R1.1 specifies transmission line relay settings
based on the highest seasonal Facility Rating using the 4-hour thermal
rating of a transmission line, plus a design margin of 150 percent.
Sub-Requirement R1.2 allows transmission line relays to be set so that
they do not operate at or below 115 percent of the highest seasonal 15-
minute Facility Rating of a circuit, when a 15-minute rating has been
calculated and published for use in real-time operations. Sub-
Requirement R1.3 allows transmission line relays to be set so that they
do not operate at or below 115 percent of the maximum theoretical power
capability.\34\ Sub-Requirement R1.4 may be applied where series
capacitors are used on long transmission lines to increase power
transfer.\35\ Sub-Requirement R1.5 applies in cases where the maximum
end-of-line three-phase fault current is small relative to the thermal
loadability of the conductor.\36\ Sub-Requirement R1.6 may be used for
system configurations where generation is remote from load busses or
main transmission busses. Under these conditions, protective relays
must be set so that they do not operate at or below 230 percent of the
aggregated generation nameplate capability in the remote area.
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\34\ The power transfer calculation may be performed by using
either an infinite source with a 1.00 per unit bus voltage at each
end of the transmission line or an impedance at each end of the
line, which reflects the actual system source impedance with a 1.05
per unit voltage behind each source impedance.
\35\ Special consideration must be made in computing the maximum
power flow that protective relays must accommodate on series-
compensated transmission lines, the greater of 115 percent of the
highest emergency rating of the series capacitor or 115 percent of
the maximum power transfer on the circuit calculated according to
sub-Requirement R1.3.
\36\ Such cases exist due to some combination of weak sources,
long lines, and the topology of the transmission system.
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22. NERC states that Sub-Requirement R1.7 is appropriate for system
configurations that have load centers that are remote from the
generation center. The protective relays at the load center terminal
must be set such that they operate only above 115 percent of the
maximum current flow from the load to generation source under any
system configuration. Sub-Requirement R1.8 applies to system
configurations that have one or more transmission lines connecting a
remote, net importing load center to the rest of the system. Under
these conditions, the protective relays at the bulk electric system end
must be set so that they operate only above 115 percent of the maximum
current flow to the load center under any system configuration.
Similarly, sub-Requirement R1.9 applies to the load end and requires
protective relays to be set so that they operate only above 115 percent
of the maximum current flow to the bulk electric system under any
system configuration. Sub-Requirement R1.10 is specific to transmission
transformer fault protective relays and transmission lines terminated
only with a transformer.\37\ Sub-Requirement R1.11 may be used when
sub-Requirement R1.10 cannot be met.\38\ Sub-Requirement R1.12 may be
used when the circuits have three or more terminals. In these cases,
line distance relays are still required to provide adequate protection
for multi-terminal circuits, but their settings (required to be set at
125 percent of the apparent impedance with a maximum torque angle at 90
degrees or the highest supported by the relay manufacturer) \39\ will
limit the desired circuit loading capability. This limited circuit
loading capability will become the Facility Rating of the circuit.
Finally, sub-Requirement R1.13 is intended to apply when otherwise
supportable situations and practical limitations are identified under
sub-Requirements R1.1 through R1.12. In these situations, the phase
protective relays must be set so that they operate above 115 percent of
such identified limitations.
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\37\ The protective relays must be set so that they operate only
above the greater of (i) 150 percent of maximum transformer
nameplate rating, and (ii) 115 percent of the highest operator
established emergency transformer rating.
\38\ In these cases additional considerations are specified to
limit unnecessary operation due to load according to one of the
following: (i) Set the relays to allow transformer overload
operation at higher than 150 percent of the maximum applicable
rating, or 115 percent of the highest operator established emergency
transformer rating whichever is greater, and allows at least 15
minutes for the operator to take controlled action to relieve the
overload, and (ii) install supervision for the relays using either a
top oil (setting no less than 100 degrees Celsius) or simulated
winding hot spot temperature elements (setting no less than 140
degrees Celsius).
\39\ Relay loadability must be evaluated at the relay trip point
at 0.85 per unit voltage and a power factor angle of 30 degrees.
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2. Requirement R2
23. Requirement R2 states that transmission owners, generator
owners, and distribution providers that use a circuit with the
protective relay settings determined by the practical limitations
described in sub-Requirements R1.6
[[Page 25466]]
through R1.9, R1.12, or R1.13 must use the calculated circuit
capability as the circuit's Facility Rating and must obtain the
agreement of the planning coordinator, transmission operator, and
reliability coordinator with the calculated circuit capability.
3. Requirement R3
24. Requirement R3 requires planning coordinators to designate
which transmission lines and transformers with low-voltage terminals
operated or connected between 100 kV and 200 kV are critical to the
reliability of the bulk electric system (because they prevent a
cascade) and therefore subject to Requirement R1.\40\ Sub-Requirements
R3.1 and R3.1.1 specify that planning coordinators must identify these
facilities through a process that considers input from adjoining
planning coordinators and affected reliability coordinators. Sub-
Requirements R3.2 and R3.3 require planning coordinators to maintain a
list of these facilities and provide it to reliability coordinators,
transmission owners, generator owners, and distribution providers
within 30 days of its initial establishment, and within 30 days of any
subsequent change.
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\40\ The Commission notes that ``planning coordinator'' is an
undefined entity in the NERC Glossary of Terms Used in Reliability
Standards. The Commission understands that the ERO has proposed to
implement the term ``planning coordinator'' in its glossary in a
separate proceeding currently before the Commission.
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B. Interactions With Other Standards
25. NERC states that proposed Reliability Standard PRC-023-1
interacts with several existing Reliability Standards, including: FAC-
008-1,\41\ FAC-009-1,\42\ IRO-002-1,\43\ IRO-005-1,\44\ and TOP-008-
1.\45\ NERC states that the interactions between these Reliability
Standards and the proposed Reliability Standard require that limits be
established for all system elements, interconnected systems be operated
within these limits, operators take immediate action to mitigate
operation outside these limits, and protective relays refrain from
operating until the observed condition on their protected element
exceeds these limits.
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\41\ FAC-008-1 requires that transmission owners and generator
owners have a Facility Ratings methodology.
\42\ FAC-009-1 requires that transmission owners and generator
owners establish Facility Ratings for their equipment and distribute
them to affected entities.
\43\ IRO-002-1 requires that reliability coordinators have
sufficient monitoring to ensure that potential or actual System
Operating Limits or Interconnection Reliability Operating Limits are
identified.
\44\ IRO-005-1 requires that reliability coordinators be aware
at all times of the current state of the interconnected system
(including all pre-contingency element conditions) and all post-
contingency element conditions, and have mitigation plans to
alleviate System Operating Limit or Interconnection Reliability
Operating Limit violations.
\45\ TOP-008-1 requires that transmission operators operate
their systems to avoid System Operating Limit and Interconnection
Reliability Operating Limit violations and take immediate steps to
alleviate the conditions causing the violations when they occur.
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C. Effective Date
26. NERC proposes that PRC-023-1 be made effective consistent with
the implementation plan specified in proposed Reliability Standard.\46\
That plan proposes that Requirements R1 and R2 be made effective on the
beginning of the first calendar quarter following applicable regulatory
approvals. For smaller facilities deemed critical to system reliability
that are subject to Requirements R1 and R2, NERC proposes an effective
date of the beginning of the first calendar quarter 39 months after
applicable regulatory approvals. NERC also proposes that, upon being
notified that a facility operated between 100 kV and 200 kV has been
added to the critical facilities list established in Requirement R3,
the facility owner will have 24 months to comply with Requirement R1
and its sub-requirements. For Requirement R3, NERC proposes an
effective date of 18 months following applicable regulatory approvals.
NERC states that the technical requirements of the proposed Reliability
Standard have been voluntarily implemented by most applicable entities
starting in January 2005.
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\46\ On February 2, 2009, NERC filed an erratum to its petition
to address an inadvertent reference to the requested effective date.
NERC requests that the Reliability Standard be made effective
consistent with the implementation plan accompanying the Reliability
Standard.
---------------------------------------------------------------------------
27. NERC also proposes to include a footnote to the ``Effective
Dates'' section that states that entities that have received temporary
exceptions approved by the NERC Planning Committee (via the NERC System
and Protection and Control Task Force) before approval of the proposed
Reliability Standard shall not be found in non-compliance with the
Reliability Standard or receive sanctions if: (1) The approved requests
for temporary exceptions include a mitigation plan (including schedule)
to come into full compliance and (2) the non-conforming relay settings
are mitigated according to the approved mitigation plan.
III. Discussion
A. Legal Standard
28. Section 215(d)(2) of the FPA states that the Commission may
approve, by rule or order, a proposed Reliability Standard or
modification to a Reliability Standard if it determines that the
Standard is just, reasonable, not unduly discriminatory or
preferential, and in the public interest.\47\ If the Commission
disapproves of the proposed Standard in whole or in part, it must
remand the proposed Standard to the ERO for further consideration.\48\
Section 215(d)(5) grants the Commission authority, upon its own motion
or upon complaint, to order the ERO to submit to the Commission a
proposed Reliability Standard or a modification to a Reliability
Standard that addresses a specific matter if the Commission considers
such a modified Reliability Standard appropriate to carry out section
215.
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\47\ 16 U.S.C. 824o(d)(2).
\48\ 16 U.S.C. 824o(d)(4).
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29. Unlike Reliability Standards, which set forth requirements with
which applicable entities must comply, violation risk factors and
violation severity levels do not set forth requirements, but instead
are factors used in the determination of a monetary penalty for a
violation of a Reliability Standard requirement.\49\ The Commission's
authority to revise violation risk factors and violation severity
levels is not circumscribed by section 215(d).
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\49\ North American Electric Reliability Corp., 123 FERC ]
61,284, at P 15 (2008); North American Electric Reliability Corp.,
119 FERC ] 61,145 at P 17, order on reh'g and compliance filing, 120
FERC ] 61,145 (2007).
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B. Decision
30. Pursuant to section 215(d)(2) of the FPA, the Commission
proposes to approve Reliability Standard PRC-023-1 as just, reasonable,
not unduly discriminatory or preferential, and in the public interest.
The Commission agrees with the ERO that PRC-023-1 is a significant step
toward improving the reliability of the Bulk-Power System in North
America because it requires that protective relay settings provide
essential facility protection for faults, while allowing the Bulk-Power
System to be operated in accordance with established Facility Ratings.
31. As stated by NERC, Reliability Standard PRC-023-1 interacts
with several existing Reliability Standards. Reliability Standards are
intended to provide coordinated and complementary requirements that
ensure reliable operation of the Bulk-
[[Page 25467]]
Power System.\50\ Consequently, in implementing PRC-023-1, registered
entities must comply with the requirements of other Reliability
Standards. For example, protective relay settings determined and
applied in accordance with the requirements of PRC-023-1 must be
included in determining system performance, System Operating Limits,
and Interconnection Reliability Operating Limits, and must be
coordinated with other protective relay settings as required by the
applicable Reliability Coordination (IRO), Transmission Operations
(TOP), and TPL Reliability Standards.\51\ Only in this way can the
entity satisfy its obligations under other Reliability Standards and
comply with the requirement in PRC-023-1 to set protective relays while
``maintaining reliable protection of the bulk electric system for all
fault conditions.'' \52\
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\50\ For example, the critical clearing time needed to achieve
the criteria identified in Table 1 of the TPL Reliability Standards
would be an input to the coordination of protection systems in
Reliability Standard PRC-001-1.
\51\ See Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, FERC Stats. & Regs. ] 31,242, at P 1435,
order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007)
(``Protection systems on Bulk-Power System elements are an integral
part of reliable operations * * * In deriving [System Operating
Limits] and [Interconnection Reliability Operating Limits],
moreover, the functions, settings, and limitations of protection
systems are recognized and integrated.'').
\52\ PRC-023-1, Requirement R1.
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32. Similarly, Reliability Standards TPL-001-0 through TPL-004-0
require annual system assessments to determine if the system meets
performance requirements, and if not, to determine what corrective
action plans must be implemented.\53\ In the Commission's view,
protective relay settings of both primary and backup systems
implemented in accordance with PRC-023-1 are subject to these
requirements and must be considered as part of performing a valid
assessment.\54\
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\53\ See TPL-002-0 and TPL-003-0 Reliability Standards,
Requirements R1 and R2.
\54\ See TPL-002-0 through TPL-004-0, Requirement R1.
---------------------------------------------------------------------------
33. The Commission also emphasizes that the requirements of PRC-
023-1 apply to all protection systems as described in Attachment A that
provide protection to the facilities defined in sections 4.1.1 through
4.1.4 of PRC-023-1, regardless of whether the protection systems
provide primary or backup protection and regardless of their physical
location. This is because protective relays are always applied to
protect specific system elements,\55\ such that when PRC-023-1 states
that it governs certain protection systems ``applied to'' certain
facilities, it means that the specified protection systems must be set
according to its requirements if they are applied to protect the
specified facilities. Consequently, transmission owners, generator
owners, and distribution providers with protective relays applied to
protect the facilities defined in sections 4.1.1 through 4.1.4 of PRC-
023-1 must set the relays according to PRC-023-1's requirements. For
example, a protective relay physically installed on the low-voltage
side of a generator step-up transformer with the purpose of providing
backup protection to a transmission line operated above 200 kV must be
set in accordance with the requirements of PRC-023-1 because it is
applied to protect a facility defined in the PRC-023-1. This is an
important aspect of PRC-023-1 because it ensures that all protective
relays subject to it that protect and could therefore disconnect the
facilities defined in it are set in accordance with its requirements,
thereby avoiding a gap in protection that would undermine its goal of
ensuring reliable operation.
---------------------------------------------------------------------------
\55\ See e.g. Reliability Standard PRC-001-1, Requirement R1
(requiring that ``[e]ach Transmission Operator, Balancing Authority,
and Generator Operator shall be familiar with the purpose and
limitations of protection system schemes applied in its area.'')
(emphasis added).
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34. Additionally, pursuant to section 215(d)(5) of the FPA, the
Commission proposes to direct the ERO to use its Reliability Standards
development process to modify PRC-023-1 to address specific concerns.
The Commission also proposes to direct the ERO to revise certain
violation risk factors and violation severity levels for PRC-023-1 by
applying the guidelines set forth in the Violation Risk Factor Order
\56\ and the Violation Severity Level Order.\57\ As discussed below,
the Commission also reminds the ERO that there are other concerns
identified in the Final Blackout Report that the ERO should address and
seeks ERO and public comment to gather more information about these
issues. After being informed by the ERO and public comment, the
Commission may, in the final rule, direct the ERO to develop further
modifications to PRC-023-1.
---------------------------------------------------------------------------
\56\ North American Electric Reliability Corp., 119 FERC ]
61,145, order on reh'g and compliance filing, 120 FERC ] 61,145
(2007) (Violation Risk Factor Order).
\57\ North American Electric Reliability Corporation, 123 FERC ]
61,284, order on reh'g and compliance filing, 125 FERC ] 61,212
(2008) (Violation Severity Level Order).
---------------------------------------------------------------------------
C. Applicability
35. NERC proposes that Reliability Standard PRC-023-1 apply to
transmission owners, generator owners, and distribution providers with
load-responsive phase protection systems as described in Attachment A
to PRC-023-1, applied to all transmission lines and transformers with
low-voltage terminals operated or connected at 200 kV and above, and to
those transmission lines and transformers with low-voltage terminals
operated or connected between 100 kV and 200 kV that are designated by
planning coordinators as critical to the reliability of the bulk
electric system.\58\ The Commission seeks comment on PRC-023-1's
applicability with respect to: (1) Transmission owners, generator
owners, and distribution providers with facilities operated between 100
kV and 200 kV and facilities operated below 100 kV that are designated
as critical to the reliability of the bulk electric system; and (2)
generator step-up and auxiliary transformers.
---------------------------------------------------------------------------
\58\ Section 4 (Applicability) of the proposed Standard
provides:
4.1. Transmission Owners with load-responsive phase protection
systems as described in Attachment A, applied to facilities defined
below:
4.1.1 Transmission lines operated at 200 kV and above.
4.1.2 Transmission lines operated at 100 kV to 200 kV as
designated by the Planning Coordinator as critical to the
reliability of the Bulk Electric System.
4.1.3 Transformers with low voltage terminals connected at 200
kV and above.
4.1.4 Transformers with low voltage terminals connected at 100
kV to 200 kV as designated by the Planning Coordinator as critical
to the reliability of the Bulk Electric System.
4.2. Generator Owners with load-responsive phase protection
systems as described in Attachment A, applied to facilities defined
in 4.1.1 through 4.1.4.
4.3. Distribution Providers with load-responsive phase
protection systems as described in Attachment A, applied according
to facilities defined in 4.1.1 through 4.1.4., provided that those
facilities have bi-directional flow capabilities.
4.4. Planning Coordinators.
---------------------------------------------------------------------------
1. Applicability to Entities With Facilities Operated Between 100 kV
and 200 kV and to Facilities Operated Below 100 kV That Are Critical to
the Reliability of the Bulk Electric System
36. Requirement R3 and its sub-requirements require the planning
coordinator to have a process to determine and maintain a list of
facilities operated between 100 kV and 200 kV that are critical to the
reliability of the bulk electric system and are therefore subject to
Requirement R1. There is no similar requirement for facilities operated
below 100 kV that are designated by Regional Entities as critical to
reliability.
37. In its petition, NERC states that it decided not to make PRC-
023-1 applicable to all facilities operated above 100 kV because doing
so would
[[Page 25468]]
increase implementation costs ``by approximately two orders of
magnitude'' and distract financial, analytical, and staff resources
from other areas that it claims have a higher effect on
reliability.\59\ NERC also claims that making PRC-023-1 applicable to
all circuits 100 kV and above (absent a determination of criticality as
established in the Requirements) would have little additional benefit
to the reliability of the interconnected system.\60\ NERC states that
the protection of circuits above 200 kV is considerably demanding of
the most protective relays, and it is therefore customary that most
modern protective relays are applied to circuits above 200 kV.\61\ NERC
further states that communications-based relaying, which can detect
faults over the entire length of a circuit as well as provide
communications-based backup protection (rather than backup protection
based on overreaching distance relays) is much more common at 200 kV
and above, and that the substation bus arrangements at 200 kV and above
diminish the need for relays at remote locations that will detect
faults in the event of protective equipment failure.\62\ NERC states
that these factors contributed to its decision to make PRC-023-1
universally applicable to all facilities 200 kV and above, and to make
it applicable only to facilities between 100 kV and 200 kV that are
designated as critical to the reliability of the bulk electric
system.\63\
---------------------------------------------------------------------------
\59\ NERC Petition at 19, 41.
\60\ Id. at 19.
\61\ Id. at 23.
\62\ Id.
\63\ Id.
---------------------------------------------------------------------------
38. NERC does not specifically address facilities operated below
100 kV that are designated by Regional Entities as critical to
reliability, but it explains in general that it decided to make PRC-
023-1 voltage-level-specific because the definition of what is included
in the ``bulk electric system'' varies throughout the eight Regional
Entities and because the effects of PRC-023-1 are not constrained to
regional boundaries.\64\
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\64\ Id. at 18-19; 39-41. For example, if one Region has purely
performance-based criteria and an adjoining Region has voltage-based
criteria, these criteria may not permit consideration of the effects
of protective relay operation in one Region upon the behavior of
facilities in the adjoining Region.
---------------------------------------------------------------------------
Commission Proposal
39. The Commission expects that the planning coordinator's process
for determining the facilities operated between 100 kV and 200 kV that
are critical to the reliability of the bulk electric system will be
robust enough to identify all such facilities and will be consistent
across regions. With this in mind, the Commission is concerned that the
approach established in Requirement R3 may not meet these expectations.
40. Requirement R3 uses an ``add in'' approach to identify
facilities operated between 100 kV and 200 kV that are critical to the
reliability of the bulk electric system and therefore subject to
Requirement R1 (i.e., initially exclude facilities operated between 100
kV and 200 kV from the requirements of the Standard, then through study
``add in'' facilities that are determined to be critical to the
reliability of the bulk electric system). Since approximately 85
percent of circuit miles of electric transmission are operated at 253
kV and below,\65\ the Commission believes that the approach in
Requirement R3 may not result in a comprehensive study to identify
applicable facilities and, at the outset, will effectively exempt a
large percentage of bulk electric system facilities that should
otherwise be subject to the Reliability Standard. In fact, NERC
acknowledged that an ``add in'' approach resulted in such an outcome
with respect to the identification of Critical Cyber Assets.\66\
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\65\ U.S. Department of Energy, ``The Electric System Delivery
Report'' issued in 2006 indicates that of the 635,000 miles of U.S.
electric transmission, approximately 538,000 miles (342,000 miles
132 kV and below; 196,000 miles 132 kV-253 kV) are 253 kV and below.
\66\ In an April 7, 2009 letter to industry stakeholders, NERC
commented on the results of the self-certification compliance survey
for Reliability Standard CIP-002-1 Critical Cyber Asset
Identification. NERC stated that survey results indicate that
entities may not have taken a comprehensive approach to identifying
Critical Assets in all cases, and instead relied on an ``add in''
approach to identify assets. Because of this, NERC stated that a
``rule out'' approach may be more appropriate and requested that
entities re-do their identification process for Critical Assets.
---------------------------------------------------------------------------
41. In its report on the 2003 blackout, NERC recommended that all
transmission owners should evaluate the zone 3 relay settings
``operating at 230 kV and above.'' \67\ In the Final Blackout Report,
the Task Force recommended that NERC go further than it had proposed
and ``broaden the review to include operationally significant 115 kV
and 138 kV lines, e.g., lines that are part of monitored flowgates or
interfaces.'' \68\ While NERC offers a general explanation of why it
proposed that PRC-023-1 apply only to facilities operated at 200 kV and
above,\69\ it does not provide a technical analysis to support the
``add in'' approach in Requirement R3. During the 2003 blackout, load-
responsive phase protection relays without communications-based
relaying operated unnecessarily, contributing to cascading outages.
This occurred for facilities operated above and below 200 kV. While
NERC asserts that most facilities operated at 200 kV and above have
communications-based relaying, it also states that facilities operated
at lower voltages generally do not.\70\ Consequently, facilities
operated below 200 kV remain vulnerable to the same problems that
contributed to cascading during the 2003 blackout.
---------------------------------------------------------------------------
\67\ NERC Report at 13.
\68\ Final Blackout Report at 158.
\69\ NERC Petition at 23.
\70\ Id.
---------------------------------------------------------------------------
42. Moreover, the Commission is not persuaded by NERC's unsupported
assertion that subjecting all facilities operated above 100 kV to PRC-
023-1 would increase implementation costs ``by approximately two orders
of magnitude'' and distract financial, analytical, and staff resources
from other areas that might have a greater impact on reliability. PRC-
023-1 implements a Final Blackout Report recommendation that was
specifically developed to prevent cascading outages. The Commission
believes that there is no area that has a greater impact on the
reliability of the bulk electric system than preventing cascading
outages. Consequently, ensuring that PRC-023-1 applies to all
facilities that are critical to the reliability of the bulk electric
system is necessary for it to achieve its intended reliability
objective.
43. In order to meet this goal, it is the Commission's view that
the process for determining the facilities operated between 100 kV and
200 kV that are critical to the reliability of the bulk electric system
must include the same system simulations and assessments that are
required by the TPL Reliability Standards for reliable operation for
all Category of Contingencies used in transmission planning.\71\ The
Commission believes that such an assessment would ensure that for all
operating configurations, the bulk electric system facilities subject
to the proposed Reliability Standard would have the appropriate
settings applied to their protective relays. The Commission expects
that a comprehensive process to determine which facilities are critical
to the reliability of the bulk electric system should necessarily
identify nearly every facility operated at or above 100 kV.
[[Page 25469]]
This is because a large percentage of the bulk electric system not only
falls into the 100 kV to 200 kV category, but also supports the
reliability of the high voltage transmission system (200 kV and above).
Therefore, the Commission proposes to direct the ERO to modify PRC-023-
1 to make it applicable to all facilities operated at or above 100 kV.
The Commission recognizes that there might be a few limited examples of
facilities operated between 100 kV and 200 kV that are not critical to
the reliability of the bulk electric system. Therefore, the Commission
also proposes to consider exceptions on a case-by-case basis for
facilities operated between 100 kV to 200 kV that demonstrably would
not result in cascading outages, instability, uncontrolled separation,
violation of facility ratings, or interruption of firm transmission
service.
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\71\ See TPL-002-0 and TPL-003-0 Reliability Standards,
Requirements R1.3, and R1.3.1 through R1.3.12. For example, for PRC-
023-1, the Commission expects that the base cases used to determine
the applicable facilities would include various generation
dispatches, topologies, and maintenance outages, and would consider
the effect of redundant and backup protection systems.
---------------------------------------------------------------------------
44. The Commission also believes that facilities that have been
identified as necessary for reliable operation of the bulk electric
system, as identified in the Compliance Registry,\72\ should be made
subject to the proposed Reliability Standard. Although the proposed
Reliability Standard does not apply to transmission owners with
facilities operated below 100 kV, and such facilities are not included
in NERC's standard definition of the bulk electric system, NERC
acknowledges that the definition ``allows for [r]egional variations in
the definition of bulk electric system.'' \73\ Thus, NERC's Statement
of Compliance Registry Criteria,\74\ defines entities with transmission
facilities operated below 100 kV that are designated by a Regional
Entity as critical to reliability as ``transmission owner[s]/
operator[s]'' subject to the requirements of the compliance registry
and therefore to the requirements of Reliability Standards.\75\ In
other words, NERC acknowledges that there are facilities operated below
100 kV that are critical to the reliability of the bulk electric
system.
---------------------------------------------------------------------------
\72\ NERC maintains a registry of entities that are required to
comply with approved Reliability Standards to the extent that they
are owners, operators, and users of the bulk power system, perform a
function listed in the functional types identified in the Statement
of Compliance Registry Criteria, and are material to the reliable
operation of the interconnected bulk power system as defined by the
Statement of Compliance Registry Criteria.
\73\ NERC Petition at 40. NERC defines the Bulk Electric System
thusly:
As defined by the Regional Reliability Organization, the
electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial
transmission facilities serving only load with one transmission
source are generally not included in this definition.
\74\ In the Statement of Compliance Registry Criteria, NERC
states that it will include in its compliance registry each entity
that it concludes can materially impact the reliability of the bulk
power system. NERC Statement of Compliance Registry Criteria
(Revision 5.0) at 3 (October 16, 2008). See North American Electric
Reliability Corp., 125 FERC ] 61,057 (2008) (accepting revisions to
NERC's Registry Criteria).
\75\ The Statement of Compliance Registry Criteria defines
``transmission owner/operator'' as:
III.d.1 An entity that owns or operates an integrated
transmission element associated with the bulk power system 100 kV
and above, or lower voltage as defined by the Regional Entity
necessary to provide for the reliable operation of the
interconnected transmission grid; or
III.d.2 An entity that owns/operates a transmission element
below 100 kV associated with a facility that is included on a
critical facilities list defined by the Regional Entity.
---------------------------------------------------------------------------
45. In Order No. 693, the Commission accepted the NERC definition
of bulk electric system but expressed concern about the potential for
gaps in coverage of facilities with regard to regional definitions.\76\
In the Commission's view, NERC has failed to provide a sufficient
technical record to justify the exemption of facilities operated below
100 kV that have been identified by the Regional Entity as necessary to
the reliability of the bulk electric system. Consequently, the
Commission proposes to direct the ERO to modify PRC-023-1 to make it
applicable to facilities operated below 100 kV that are designated by
the Regional Entity as critical to the reliability of the bulk electric
system. The Commission understands that conforming modifications to the
requirements of PRC-023-1 will be necessary to reflect these proposals.
The Commission requests comment on each of its proposals.
---------------------------------------------------------------------------
\76\ Order No. 693, FERC Stats. & Regs. ] 31,242, at P 77.
---------------------------------------------------------------------------
2. Generator Step-Up and Auxiliary Transformers
46. NERC states that generator step-up transformer relay
loadability was intentionally omitted from PRC-023-1.\77\ NERC contends
that generator step-up relay loadability merits particular attention in
the area of generator protection, and therefore that it would be
inappropriate to include it in a transmission relay loadability
standard without consideration of the overall generator protective
system in place. NERC claims that it is ``imperative'' that generator
step-up transformer protection settings be coordinated with other
generator protection functions as well as the associated local
transmission system protection.\78\ NERC states that this requires
careful consideration of the transient, sub-transient, and steady state
generator responses to system conditions, and consideration of how the
resultant loadings on the generator step-up factor into
loadability.\79\
---------------------------------------------------------------------------
\77\ NERC Petition at 38.
\78\ Id.
\79\ Id.
---------------------------------------------------------------------------
47. NERC states that the Standard Drafting Team did not include
technical experts from the generator industry. NERC explains that to
include generation it would have had to identify and recruit additional
experts, delaying the presentation of PRC-023-1 by six months. NERC
states that generator protection standards for relay loadability will
be addressed in future Reliability Standards.
Commission Proposal
48. It is the Commission's intention that the ERO address in a
timely manner the reliability objectives relevant to relay loadability,
which include generator step-up and auxiliary transformers. One way to
ensure that this occurs is for the Commission to direct the ERO to
modify the proposed Reliability Standard to address these issues. This
approach also has the advantage of placing coordination between
generator and transmission protection systems in the same Reliability
Standard. Consequently, the Commission seeks comment on whether it
should direct the ERO to modify the proposed Reliability Standard to
address generator step-up and auxiliary transformer loadability, or
whether generator step-up and auxiliary transformer loadability should
be addressed in a separate Reliability Standard, as the ERO intends.
The Commission also seeks comment as to what is a reasonable timeframe
for developing a modification or separate Reliability Standard to
address generator step-up and auxiliary transformer loadability.
D. Need To Address Additional Issues
49. It is the Commission's view that to ensure reliable operation
of the system the ERO must address both the reach of zone 3/zone 2
relays applied as remote circuit breaker failure and backup protection,
and issues related to load increases, overload, and stable power swings
that occur under recognized system conditions.\80\ As proposed, PRC-
023-1 addresses only issues related to load increases and overloads
(loadability).
---------------------------------------------------------------------------
\80\ Like those issues addressed in Reliability Standards TPL-
002-0, TPL-003-0, and TPL-004-0.
---------------------------------------------------------------------------
1. Zone 3/Zone 2 Relays Applied as Remote Circuit Breaker Failure and
Backup Protection
50. Typically, zone 3/zone 2 relays are set to reach 100 percent of
the protected
[[Page 25470]]
transmission line with a margin of more than 100 percent of the longest
line (including any series elements such as transformers) that emanates
from the remote buses. If zone 3/zone 2 relays detect a fault on an
adjacent transmission line in their reach, and the relays on the
faulted line fail to operate, the zone 3/zone 2 relays will operate as
backup and remove the fault. However, when they operate they will
disconnect both the faulted transmission line and ``healthy''
facilities that should have remained in service. To ensure coordination
of protection and avoid unnecessarily disconnecting ``healthy''
facilities, zone 3/zone 2 relays are typically set to operate after a
time delay.
51. The Task Force identified fourteen 345 kV and 138 kV
transmission lines that disconnected during the 2003 blackout because
of zone 3/zone 2 relays applied as remote circuit breaker failure and
backup protection.\81\ Among the relays that operated unnecessarily
were several zone 2 relays in Michigan that overreached their protected
lines by more than 200 percent and operated without a time delay.\82\
The Task Force stated that although these and the other relays operated
according to their settings, they operated so quickly that they impeded
the natural ability of the electric system to hold together and did not
allow time for operators to try to stop the cascade.\83\
---------------------------------------------------------------------------
\81\ Final Blackout Report at 80.
\82\ Id.
\83\ Id.
---------------------------------------------------------------------------
Commission Proposal
52. The Commission is concerned that zone 3/zone 2 relays will
operate because of line load or overload in extreme contingency
conditions even in the absence of a fault.\84\ The large setting of
zone 3/zone 2 relays makes them susceptible to operating in the absence
of a fault under abnormal system conditions. This is because under
abnormal system conditions, such as very high loading and large, but
stable power swings, the current and voltage as measured by the
impedance relay may fall within the very large magnitude and phase
setting of the relay. When this occurs, the relay is susceptible to
operation.
---------------------------------------------------------------------------
\84\ Id.
---------------------------------------------------------------------------
53. NERC states in its petition that PRC-023-1 is silent on the
application of zone 3/zone 2 relays as remote circuit breaker failure
and backup protection because it establishes requirements for any load-
responsive relay regardless of its protective function.\85\ However,
given the Task Force's conclusions about the role zone 3/zone 2 played
in the spread of the cascade in the 2003 blackout, it is the
Commission's view that the ERO should develop a maximum allowable relay
reach for zone 3/zone 2 relays applied as remote circuit breaker
failure and backup protection. The Commission seeks comment on whether
it should direct the ERO to develop a maximum allowable reach, and if
so, whether it should direct the ERO to develop a modification to PRC-
023-1 or a new Reliability Standard.
---------------------------------------------------------------------------
\85\ NERC Petition at 39.
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2. Protective Relays Operating Unnecessarily Due to Stable Power Swings
54. Despite the loss of fourteen key transmission lines, the Task
Force found that during the 2003 blackout the system did not become
dynamically unstable until at least after the Hampton-Pontiac and
Thetford-Jewell 345 kV lines disconnected.\86\ These lines disconnected
in a phase of the cascade that was caused by dynamic, but stable power
swings.
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\86\ Final Blackout Report at 82-83.
---------------------------------------------------------------------------
55. Transient and stable power swings occur most commonly when a
fault and faulted facilities are quickly removed from the system,
typically within 0.1 second of detection, and the system and affected
generators stabilize within several seconds, typically within 3
seconds. Dynamic power swings can also occur when the system recovers
from a disturbance and achieves transient stability (typically within a
0-3 second time frame) and then returns to a steady state over a longer
period of time (typically within 3-30 seconds, or even minutes). Prior
to the system returning to a new steady state operating condition, it
may exhibit power swings that may decrease rapidly or increase in
magnitude. When the power swings decrease, the system will be able to
achieve a new stable operating condition, provided that the relays
protecting ``healthy'' facilities have not operated unnecessarily
because of the stable power swings.
56. Each time zone 3/zone 2 relays operated and disconnected
facilities because of high loading, the power flowing on the
transmission system increased in magnitude and oscillated, i.e.,
``swung,'' back and forth across a large portion of the interconnected
systems around Lake Erie. Initially, with each swing the transmission
system recovered and appeared to stabilize. However, as the power
swings and oscillations increased in magnitude, zone 3/zone 2 and other
relays measured levels of currents and voltages that, because of their
settings, indicated a fault. Consequently, these relays operated
unnecessarily and disconnected ``healthy'' transmission lines. As more
``healthy'' transmission lines were disconnected, power swings and
oscillations increased in magnitude causing more ``healthy'' lines to
disconnect, thus spreading the cascade.
57. The proposed Reliability Standard does not address the
unnecessary operation of protective relays due to stable power swings.
NERC states that it did not address power swings in PRC-023-1 because
the focus of the proposed Standard is on loadability at a time when
operators can take action to protect the system.\87\ NERC states that
during the 2003 blackout the power swing time frame was too short for
operators to act, which is typical for severe power swings.\88\ NERC
states that in the electrical vicinity of severe power swings, relays
cannot distinguish power swings from faults that trigger their
operation.\89\
---------------------------------------------------------------------------
\87\ NERC Petition at 39.
\88\ Id.
\89\ Id.
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Commission Proposal
58. While zone 3/zone 2 relays operated during the 2003 blackout
according to their settings and specifications, the inability of these
relays to distinguish between a dynamic, but stable power swing and an
actual fault contributed to the cascade. Because PRC-023-1 addresses
only the unnecessary operation of protective relays caused by high
loading conditions, and does not address unnecessary operation caused
by stable power swings, the Commission is concerned that relays set
according to PRC-023-1 could still operate unnecessarily because of
stable power swings.
59. NERC states that in the electrical vicinity of severe power
swings, relays cannot distinguish between stable power swings and
actual faults. However, there are several protection applications and
relays that are less susceptible to transient or dynamic power swings,
including pilot wire differential, phase comparison, and blinder-
blocking applications and relays, and impedance relays with non-
circular operating characteristics.\90\ Each of these protection
applications and relays uses existing technology and has been tested
and applied effectively
[[Page 25471]]
to mitigate relay susceptibility to power swings.
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\90\ Non-circular operating characteristics include, for
example, off-set MHO, blinder, reactance, and lenticular operating
characteristics that while still providing a long reach, are less
susceptible to power swings.
---------------------------------------------------------------------------
60. Because the inability of protective relays to distinguish
between actual faults and stable power swings contributed to the
cascade in the 2003 blackout, and given the availability of protection
applications and relays that can effectively mitigate this problem, it
is the Commission's view that the use of protective relay systems that
cannot differentiate between faults and stable power swings constitutes
mis-coordination of the protection system and is inconsistent with
entities' obligations under existing Reliability Standards.\91\ In the
Commission's view, a protective relay system that cannot refrain from
operating under non-fault conditions because of a technological
impediment is unable to achieve the performance required for reliable
operation. Consequently, the Commission seeks comment on whether it
should direct the ERO to develop a Reliability Standard or a
modification that requires applicable entities to use protective relay
systems that can differentiate between faults and stable power swings
and phases out protective relay systems that cannot meet this
requirement. The Commission may direct a Reliability Standard or a
modification in response to these comments.
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\91\ See supra P 31. As discussed previously, protective relay
settings determined and applied in accordance with the requirements
of PRC-023-1 must be included in determining system performance,
System Operating Limits, and Interconnection Reliability Operating
Limits, and must be coordinated with other protective relay settings
as required by the applicable IRO, TOP, and TPL Reliability
Standards.
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E. Concerns With the Implementation of Certain Criteria Under
Requirement R1
61. Requirement R1 establishes criteria (Requirements R1.1 through
R1.13) to prevent phase protective relay settings from limiting
transmission system loadability while maintaining reliable protection
of the bulk electric system for all fault conditions. These criteria
reflect the maximum circuit loading for the various system
configurations and conditions and permit the relays to be set for
optimum protection while carrying that load. The criterion to be used
depends on the configuration and conditions in the system in which the
protective relay will be applied.
62. The Commission is concerned that some criteria established in
Requirement R1 might accommodate the use of protective relays for
certain system configurations where the protective relays may not be
appropriate or help achieve the reliability objective of the proposed
Reliability Standard. In particular, the Commission is concerned with
the implementation of criteria established by Requirements R1.2
(Transmission Line Established 15-Minute Rating), R1.10 (Transformer
Overcurrent Protection), and R1.12 (Long Line Relay Loadability).
1. Requirement R1.2
63. Requirement R1.2 directs the transmission owner, generation
owner, or distribution provider to set transmission line relays so that
they do not operate at or below 115 percent of the highest seasonal 15-
minute Facility Rating of a circuit. A footnote attached to Requirement
R1.2 provides that ``[w]hen a 15-minute rating has been calculated and
published for use in real-time operations, the 15-minute rating can be
used to establish the loadability requirement for the protective
relays.'' \92\
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\92\ NERC states in its petition that it modified the footnote
in response to Commission staff's concern that 15-minute ratings may
be used that are not completely reflected as facility ratings. The
modification clarified that Requirement R1.2 references 15-minute
ratings where such ratings have been calculated and are used for
real-time operations. NERC Petition at 37.
---------------------------------------------------------------------------
Commission Proposal
64. The Commission is concerned that Requirement R1.2 might
conflict with Requirement R4 of existing Reliability Standard TOP-004-1
(Transmission Operations), which states that ``if a transmission
operator enters an unknown operating state, it will be considered to be
in an emergency and shall restore operations to respect proven
reliability power system limits within 30 minutes.'' \93\ The
Commission is concerned that the transmission operator (or any other
reliability entity affected by the facility) might conclude that it has
30 minutes to restore the system to normal when in fact it has only 15
minutes because the relay settings for certain transmission facilities
have been set to operate at the 15-minute rating in accordance with
Requirement R1.2. This may have an adverse impact on system
reliability, since the operator might not take Requirement R1.2 into
consideration.
---------------------------------------------------------------------------
\93\ See Reliability Standard TOP-004-1, Requirement R4.
---------------------------------------------------------------------------
65. To ensure the reliability of the Bulk-Power System, Reliability
Standards PRC-023-1 and TOP-004-1 should give a transmission operator
the same amount of time to restore the system to normal operations. The
Commission acknowledges that Requirement R1.2 references the
``publishing'' of a facility's 15-minute rating; however, we are not
persuaded that publication of a rating is sufficient to address the
potential conflict. Consequently, the Commission proposes to direct the
ERO to either revise Requirement R1.2 to apply it to Reliability
Standard TOP-004-1 or develop a new requirement that transmission
owners, generation owners, and distribution providers give their
transmission operators a list of transmission facilities that implement
Requirement R1.2, or propose an equally effective and efficient
approach to avoid the potential conflict. The Commission seeks comment
on each of these proposals.
2. Requirement R1.10
66. Requirement R1.10 establishes criteria for applicable entities
to set transformer fault protective relays and transmission line relays
on transmission lines that terminate in a transformer. For this system
configuration, protective relays would be set such that the transformer
fault protective relays and transmission line relays do not operate at
or below the greater of 150 percent of the applicable maximum
transformer name-plate rating (expressed in amperes), including the
forced cooled ratings corresponding to all installed supplemental
cooling equipment, or 115 percent of the highest owner-established
emergency transformer rating.\94\
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\94\ NERC states that the Standard Drafting Team did not contain
any experts on equipment ratings. NERC Petition at 31.
---------------------------------------------------------------------------
Commission Proposal
67. The Commission understands that facility owners determine the
ratings of their facilities based on a number of factors, and that they
use verified methodologies to determine expected temperatures and other
parameters needed to establish a rating.\95\ It is the Commission's
view, however, that overloading facilities at any time, but especially
during system faults, could lower reliability and present a safety
concern.
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\95\ The methodology for determining transformer ratings
includes analysis of all aspects of the transformer, such as
bushings, leads, stray flux heating, core heating, winding hot
spots, and the formation of bubbles at those hot spots.
---------------------------------------------------------------------------
68. The application of a transmission line terminated in a
transformer enables the transmission owner to avoid installing a bus
and local circuit breaker on both sides of the transformer. Protective
relay settings implemented according to Requirement R1.10 for this
topology would allow the transformer to be subjected to overloads
higher than its established ratings for unspecified periods of time.
Transformers that have been subjected to currents over their
[[Page 25472]]
maximum rating have been recorded as failing violently and resulted in
substantial fires. This negatively impacts reliability and raises
safety concerns. While safety considerations are outside the
jurisdiction of the Commission, requirements in a Reliability Standard
should not be interpreted as requiring unsafe actions or designs.
69. Consequently, the Commission proposes to direct the ERO to
submit a modification that requires any entity that implements
Requirement R1.10 to verify that the limiting piece of equipment is
capable of sustaining the anticipated overload current for the longest
clearing time associated with the fault from the facility owner. If the
facility owner can not verify that ability, the facility owner should
apply either different protection systems or change the topology to
avoid this configuration to be in compliance with PRC-023-1. The
Commission seeks comments on this proposal.
3. Requirement R1.12
70. Requirement R1.12 establishes relay loadability criteria when
the desired transmission line capability is limited by the requirement
to adequately protect the transmission line. In these cases, the line
distance relays are still required to provide adequate protection, but
the implemented relay settings will limit the desired loading
capability of the circuit. NERC states that in the event an essential
fault protection imposes a more constraining limit on the system, the
limit imposed by the fault protection is reflected within the facility
rating.\96\
---------------------------------------------------------------------------
\96\ NERC Petition at 14.
---------------------------------------------------------------------------
71. NERC claims that PRC-023-1 should cause no undue negative
effect on competition or restrict the grid beyond what is necessary for
reliability.\97\ It explains that, with the exception of those relays
that legitimately define and restrict the facility rating, PRC-023-1
removes arbitrary limits related to relay loadability that cause
transmission capability limitations. NERC further points out that no
market-based entity is required to comply with PRC-023-1.
---------------------------------------------------------------------------
\97\ Id. at 27.
---------------------------------------------------------------------------
Commission Proposal
72. The Commission is concerned that Requirement R1.12 allows
entities to technically comply with PRC-023-1 but not achieve its
stated purpose. Since protective relay settings are allowed to limit
the load carrying capability of a transmission line, that line is not
being utilized to its full potential in response to sudden increases in
line loadings or power swings, i.e., the natural response of the Bulk-
Power System will be less robust in response to system disturbances.
73. Entities subject to PRC-023-1 must employ a protection system
that meets their reliability obligations, but a protection system that
requires the application of Requirement R1.12 may not satisfy this
requirement. Consequently, the Commission seeks comment on whether use
of such a protection system is consistent with the reliability
objectives of PRC-023-1, and whether the Commission should direct a
modification that would require that entities that employ such a system
use a different protection relay system that would meet the reliability
objective of the Reliability Standard.
F. Requirement R3 and Its Sub-Requirements
74. Requirement R3 requires planning coordinators to designate
which transmission lines and transformers with low-voltage terminals
operated or connected between 100 kV and 200 kV are critical to the
reliability of the bulk electric system and therefore subject to
Requirement R1. Sub-Requirements R3.1 and R3.1.1 specify that planning
coordinators must determine these facilities through a process that
considers input from adjoining planning coordinators and affected
reliability coordinators. Sub-Requirements R3.2 and R3.3 require
planning coordinators to maintain a list of designated facilities and
provide it to reliability coordinators, transmission owners, generator
owners, and distribution providers within 30 days of its initial
establishment, and within 30 days of any subsequent change.
Commission Proposal
75. In light of the Commission's proposal to direct the ERO to
modify PRC-023-1 to make it applicable to all facilities operated at or
above 100 kV, with the possibility of case-by-case exceptions, and to
all facilities operated below 100 kV that are designated by the
Regional Entity as critical to the reliability of the bulk electric
system, the Commission proposes to direct the ERO to revise Requirement
R3 and Sub-Requirement R3.2 to require that the planning coordinator
maintain a list that reflects the Commission's proposal. Moreover, it
is the Commission's view that the Regional Entity should know which
facilities in its area are subject to the Reliability Standard.
Accordingly, the Commission proposes to direct the ERO to modify
Requirement R3.3 to add the Regional Entity to the list of entities
that receive the list as required by Requirement R3.2.
G. Attachment A
76. Attachment A of PRC-023-1 contains three sections: (1) A list
of examples of load-responsive relays subject to PRC-023-1, (2) a
statement that out-of-step blocking protective schemes shall be
evaluated to ensure that those applications do not block trip for fault
during the loading conditions defined within the requirements of PRC-
023-1, and (3) a list of Protective Systems that are excluded from the
requirements of the PRC-023-1. The Commission has concerns about
sections (2) and (3).
1. Section (2): Evaluation of Out-of-Step Blocking Schemes
77. Section (2) of Attachment A states that the ``[S]tandard
includes out-of-step blocking schemes which shall be evaluated to
ensure that they do not block trip for fault during the loading
conditions defined within the requirements.'' This obligation, however,
is not included as a requirement in the proposed Reliability Standard.
Instead, it is included in Attachment A. Requirements should be in the
requirements section of a Reliability Standard to ensure compliance.
Since the ERO intends to require the evaluation of out-of-step blocking
applications, language to this effect should be included as a
requirement and not as a statement in an Attachment. Consequently, the
Commission proposes to direct the ERO to modify PRC-023-1 by adding the
statement in section (2) of Attachment A as an additional requirement
with the appropriate violation risk factor and violation severity level
assignments.
2. Section (3): List of Protection Systems Excluded From the Standard
78. Section (3) lists certain protection systems that are excluded
from the requirements of PRC-023-1. However, in its petition NERC does
not provide a technical rationale for excluding any load-responsive
phase protection systems from the requirements of PRC-023-1. Thus, it
is not clear to the Commission that the exclusions in section 3 are
justified.\98\
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\98\ The exclusion of protection systems intended for the
detection of ground fault conditions appears to be unnecessary
because these systems are not load-responsive.
---------------------------------------------------------------------------
79. For example, subsection 3.1 excludes from the requirements of
PRC-023-1: (1) Overcurrent elements that are enabled only during loss
of potential conditions and (2) elements that are enabled only during a
loss of
[[Page 25473]]
communications. This subsection could be interpreted to exclude certain
protection systems that use communications to compare current
quantities and directions at both ends of a transmission line, such as
pilot wire protection or current differential protection systems
supervised by fault detector relays. The Commission understands that if
supervising fault detector relays are excluded from PRC-023-1, and are
set below the rating of the protected element, the loss of
communications and heavy line loading conditions that approach the line
rating would cause these protective relays to operate and unnecessarily
disconnect the line. If adjacent transmission lines have similar
protection systems and settings, those protection systems would also
operate unnecessarily, resulting in cascading outages.
80. The Commission seeks comment on whether the exclusions in
section 3 are technically justifiable and whether the Commission should
direct the ERO to modify PRC-023-1 by deleting specific subsections in
section 3. The Commission also seeks comment on whether it should
direct the ERO to modify subsection 3.1 to clarify that it does not
exclude from the requirements of PRC-023-1 such protection systems as
described above.
81. The Commission also notes that subsection 3.5 excludes from the
requirements of PRC-023-1 ``relay elements used only for [s]pecial
[p]rotection [s]ystems applied and approved in accordance with NERC
Reliability Standards PRC-012 through PRC-017.'' Since PRC-012-0, PRC-
013-0 and PRC-014-0 are currently proposed Reliability Standards
pending with the Commission, subsection 3.5 is not enforceable until
approved by the Commission.\99\
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\99\ Order No. 693-A, FERC Stats. & Regs. ] 31,242 at P 138.
---------------------------------------------------------------------------
H. Effective Date
82. NERC requests that PRC-023-1 be made effective consistent with
the implementation plan accompanying the Reliability Standard. For
Requirements R1 and R2, NERC proposes that transmission lines operated
at 200 kV and above and transformers with low-voltage terminals
connected at 200 kV and above (except switch-on-to fault-schemes) be
made effective on the beginning of the first calendar quarter following
applicable regulatory approvals. For transmission lines operated
between 100 kV and 200 kV and transformers with low-voltage terminals
connected between 100 kV and 200 kV that are designated by planning
coordinators as critical to the reliability of the bulk electric system
(including switch-on-to fault-schemes) in order to prevent a cascade,
NERC proposes an effective date of the beginning of the first calendar
quarter 39 months after applicable regulatory approvals. NERC also
proposes that each transmission owner, generator owner, and
distribution provider have 24 months from notification by the planning
coordinator that a facility has been added to the planning
coordinator's critical facilities list (pursuant to Requirement R3.3)
to comply with R1 and its sub-requirements. For Requirement R3, NERC
proposes an effective date of 18 months following applicable regulatory
approvals.
83. NERC also proposes to include a footnote to the ``Effective
Dates'' section that states that entities that have received temporary
exceptions approved by the NERC Planning Committee (via the NERC System
and Protection and Control Task Force) before approval of the proposed
Reliability Standard shall not be found in non-compliance with the
Reliability Standard or receive sanctions if: (1) The approved requests
for temporary exceptions include a mitigation plan (including schedule)
to come into full compliance and (2) the non-conforming relay settings
are mitigated according to the approved mitigation plan.\100\
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\100\ The footnote states:
Temporary Exceptions that have already been approved by the NERC
Planning Committee via the NERC System and Protection and Control
Task Force prior to the approval of this [Reliability] [S]tandard
shall not result in either findings of non-compliance or sanctions
if all of the following apply: (1) The approved requests for
Temporary Exceptions include a mitigation plan (including schedule)
to come into full compliance, and (2) the non-conforming relay
settings are mitigated according to the approved mitigation plan.
---------------------------------------------------------------------------
84. NERC contends this implementation plan presents a reasonable
time frame to allow all entities to be in compliance. NERC states that
the technical requirements of PRC-023-1 have been implemented by most
applicable entities starting in January 2005 under voluntary activities
directed by the NERC Planning Committee and that most entities have
provided assurances to NERC that they have implemented these technical
requirements. NERC states that the implementation period established in
the implementation plan provides an opportunity for those entities that
did not participate in the voluntary activities to comply with PRC-023-
1, and for all entities to establish the documentation necessary to
demonstrate compliance.
Commission Proposal
85. The Commission proposes to approve the implementation plan as
it relates to facilities operated at 200 kV and above. In light of the
Commission's proposal to direct the ERO to modify PRC-023-1 to make it
applicable to all facilities operated at or above 100 kV, with the
possibility of case-by-case exceptions, and to all facilities operated
below 100 kV that are designated by the Regional Entity as critical to
the reliability of the bulk electric system, the Commission proposes an
effective date of 18 months following applicable regulatory approvals
for facilities operated below 200 kV. The Commission seeks comment on
these proposals.
86. The Commission proposes not to approve the temporary exemption
of certain entities from enforcement actions while they come into
compliance with PRC-023-1's requirements. In the Commission's view, it
is best that discussions about potential enforcement actions are left
out of a Reliability Standard and instead handled by NERC's compliance
and enforcement program. Consequently, the Commission proposes to
direct the ERO to modify PRC-023-1 by removing the footnote.
I. Violation Risk Factors
87. As part of its compliance and enforcement program, NERC assigns
a low, medium, or high violation risk factor to each requirement of
each mandatory Reliability Standard to associate a violation of the
requirement with its potential impact on the reliability of the Bulk-
Power System. Violation risk factors are defined as follows:
High Risk Requirement: (a) Is a requirement that, if violated,
could directly cause or contribute to Bulk-Power System instability,
separation, or a cascading sequence of failures, or could place the
Bulk-Power System at an unacceptable risk of instability,
separation, or cascading failures; or (b) is a requirement in a
planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations,
directly cause or contribute to Bulk-Power System instability,
separation, or a cascading sequence of failures, or could place the
Bulk-Power System at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement: (a) Is a requirement that, if violated,
could directly affect the electrical state or the capability of the
Bulk-Power System, or the ability to effectively monitor and control
the Bulk-Power System, but is unlikely to lead to Bulk-Power System
instability, separation, or
[[Page 25474]]
cascading failures; or (b) is a requirement in a planning time frame
that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly affect the
electrical state or capability of the Bulk-Power System, or the
ability to effectively monitor, control, or restore the Bulk-Power
System, but is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to lead to Bulk-Power
System instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement: Is administrative in nature and (a) is a
requirement that, if violated, would not be expected to affect the
electrical state or capability of the Bulk-Power System, or the
ability to effectively monitor and control the Bulk-Power System; or
(b) is a requirement in a planning time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to affect the
electrical state or capability of the Bulk-Power System, or the
ability to effectively monitor, control, or restore the Bulk-Power
System.\101\
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\101\ Violation Risk Factor Order, 119 FERC ] 61,145 at P 9.
88. In the Violation Risk Factor Order, the Commission addressed
violation risk factors filed by NERC for Version 0 and Version 1
Reliability Standards. In that order, the Commission used five
guidelines for evaluating the validity of each violation risk factor
assignment: (1) Consistency with the conclusions of the Final Blackout
Report; (2) consistency within a Reliability Standard; (3) consistency
among Reliability Standards with similar Requirements; (4) consistency
with NERC's proposed definition of the violation risk factor level; and
(5) assignment of violation risk factor levels to those requirements in
certain Reliability Standards that co-mingle a higher risk reliability
objective and a lower risk reliability objective.\102\
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\102\ For a complete discussion of each guideline, see id. P 19-
36.
---------------------------------------------------------------------------
89. In its petition, NERC assigned violation risk factors only to
the main requirements of the proposed Reliability Standard and did not
assign violation risk factors to any of the sub-requirements.\103\ NERC
assigns Requirement R1 a high violation risk factor, Requirement R2 a
medium violation risk factor, and Requirement R3 a medium violation
risk factor.
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\103\ We note that, in Version Two Facilities Design,
Connections and Maintenance Reliability Standards, Order No. 722,
126 FERC ] 61,255 at P 45 (2009), the ERO proposed to develop
violation risk factors and violation severity levels for
Requirements but not sub-requirements. The Commission denied the
proposal as ``premature'' and, instead, encouraged the ERO to
``develop a new and comprehensive approach that would better
facilitate the assignment of violation severity levels and violation
risk factors.''
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90. As an initial matter, NERC's compliance and enforcement program
requires it to assign a violation risk factor to each sub-requirement
of a proposed Reliability Standard. In addition, the Violation Severity
Level Order stated that each requirement assigned a violation risk
factor also must be assigned at least one violation severity
level.\104\ As set forth in the NERC's Sanction Guidelines, the
intersection of these two factors is the first step in the
determination of a monetary penalty for a violation of a requirement of
a Reliability Standard. Therefore, consistent with Commission precedent
and NERC's Sanction Guidelines, each requirement must have a violation
risk factor and violation severity level assignment.
---------------------------------------------------------------------------
\104\ Violation Severity Level Order, 123 FERC ] 61,284 at P 3.
---------------------------------------------------------------------------
1. Requirement R1 and Its Sub-Requirements
91. Requirement R1 establishes criteria (sub-Requirements R1.1-
R1.13) to prevent phase protective relay settings from limiting
transmission system loadability while maintaining reliable protection
of the bulk electric system for all fault conditions.\105\ NERC assigns
Requirement R1 a high violation risk factor. The Commission agrees that
Requirement R1 should be assigned a high violation risk factor because
a violation of Requirement R1 has the potential to cause cascading
outages like those that occurred during the 2003 blackout. NERC did not
assign violation risk factors to sub-Requirements R1.1 through R1.13.
---------------------------------------------------------------------------
\105\ Requirement R1 also requires each transmission owner,
generator owner, and distribution provider to evaluate relay
loadability at 0.85 per unit voltage and a power factor angle of 30
degrees.
---------------------------------------------------------------------------
Commission Proposal
92. The Commission agrees that Requirement R1 should be assigned a
high violation risk factor because a violation of Requirement R1 has
the potential to cause cascading outages like those that occurred
during the 2003 blackout. It is the Commission's view that because the
sub-requirements in Requirement R1 set forth criteria for compliance
with Requirement R1, the reliability risk of a violation of any one of
the sub-requirements is the same as with a violation of Requirement R1.
Therefore, consistent with the high violation risk factor assigned to
Requirement R1, the Commission proposes to direct the ERO to assign a
high violation risk factor to each of the sub-Requirements R1.1 through
R1.13. The Commission seeks comment on this proposal.
2. Requirement R3
93. Requirement R3 requires planning coordinators to designate
which transmission lines and transformers with low-voltage terminals
operated or connected between 100 kV and 200 kV are critical to the
reliability of the bulk electric system in order to prevent a cascade
and therefore should be subject to Requirement R1. NERC assigns
Requirement R3 a medium violation risk factor.
Commission Proposal
94. In light of the Commission's proposal to direct the ERO to
modify Requirement R3 and its sub-requirements, the Commission proposes
to direct the ERO to assign a violation risk factor to the revised
Requirement R3 and its revised sub-requirements that is consistent with
the revisions and the Violation Risk Factor Guidelines.
J. Violation Severity Levels
95. For each requirement of a Reliability Standard, NERC states
that it will also define up to four violation severity levels--lower,
moderate, high and severe--as measurements of the degree to which the
requirement was violated. For a specific violation of a particular
requirement, NERC or the Regional Entity will establish the initial
value range for the base penalty amount by finding the intersection of
the applicable violation risk factor and violation severity level in
the Base Penalty Amount Table in Appendix A of the Sanction
Guidelines.\106\
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\106\ See North American Electric Reliability Corp., 119 FERC ]
61,248 at P 74, order on clarification, 120 FERC ] 61,239 (2007)
(directing NERC to develop up to four violation severity levels
(lower, moderate, high, and severe) as measurements of the degree of
a violation for each requirement and sub-requirement of a
Reliability Standard and submit a compliance filing by March 1,
2008.).
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96. In the Violation Severity Level Order, the Commission addressed
violation severity level assignments filed by NERC for the 83
Reliability Standards approved in Order No. 693. In that order, the
Commission developed four guidelines for evaluating violation severity
levels filed by NERC: (1) Violation severity level assignments should
not have the unintended consequence of lowering the current level of
compliance; (2) violation severity level assignments should ensure
uniformity and consistency among all approved Reliability Standards in
the determination of penalties; (3) violation severity level
assignments should be consistent with the corresponding requirement;
and (4) violation severity level assignments should be based on a
single violation,
[[Page 25475]]
not on a cumulative number of violations.\107\
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\107\ For a complete discussion of each guideline, see the
Violation Severity Level Order, 123 FERC ] 61,284 at P 19-36.
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97. In its petition, NERC proposes violation severity levels for
Requirements R1, R2, and R3. NERC did not propose violation severity
levels for sub-Requirements R1.1 through R1.13 and R3.1 through R3.3.
98. The Commission is concerned that the violation severity levels
assigned to Requirements R1 and R2 may not be consistent with certain
guidelines set forth in the Violation Severity Level Order. Moreover,
NERC did not propose violation severity levels for any sub-
requirements. As discussed previously, each requirement that is
assigned a violation risk factor must also be assigned at least one
violation severity level. Accordingly, the Commission proposes to
direct the ERO to revise violation severity levels assigned to
Requirements R1 and R2 as well as to submit violation severity levels
for sub-Requirements R1.1 through R1.13 that are consistent with the
guidelines set forth in the Violation Severity Order as discussed
below.
1. Requirement R1
99. Requirement R1 and sub-Requirements R1.1 through R1.13
establish criteria to be used for setting phase protective relays. NERC
proposes violation severity levels that assign a ``moderate'' severity
for a violation when the applicable entity complied with the criteria,
but its evidence of compliance is incomplete or incorrect for one or
more of the criteria and a ``severe'' violation when the relays'
settings do not comply with any of the criteria or evidence does not
exist to support compliance with any one of the criteria.
Commission Proposal
100. It is the Commission's view that the violation severity levels
NERC assigns to Requirement R1 combine the degree or severity of a
violation of the Requirement (e.g., the relay settings do not comply
with any of the sub-requirements) with an outcome with regard to
determining compliance with the Requirement (e.g., evidence that the
relay settings comply with the sub-requirements). For example,
Guideline 3 ensures that assigned violation severity levels are
consistent with the corresponding requirement i.e., the degrees of non-
compliance are based on the text of the requirement. The text of
Requirement R1 does not explicitly state that the applicable entity
have evidence that the relay settings comply with the criteria set
forth in the sub-Requirements R1.1 through R1.13; only that the
applicable entity use criteria. The Commission believes that having
evidence that the relay settings comply with the criteria is an outcome
that is expected with compliance with the Requirement. This is
consistent with NERC's description of a requirement's ``Measure'' and
not indicative of the degree to which the Requirement was
violated.\108\ As such, since the text of the assigned violation
severity level as it is not consistent with the corresponding
requirement, the assigned violation severity levels are not consistent
with Guideline 3.
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\108\ NERC Reliability Standards Development Procedure, see
descriptions of ``Measure'' and ``Violation Severity Level.''
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101. The Commission believes that violation severity levels for
Requirement R1 and its sub-requirements could be assigned applying a
binary approach; i.e., either an entity applied the criteria or it did
not. Consistent with the binary approach, a single violation severity
level assignment for Requirement R1 and single violation severity level
for each of the sub-Requirements R1.1 through R1.13 is appropriate.
Therefore, the Commission proposes to direct the ERO to assign a single
violation severity level to Requirement R1 and a single violation
severity level to each of the sub-Requirements R1.1 through R1.13,
consistent with its Guideline 2a compliance filing in Docket No. RR08-
4-004 and seeks comment on this proposal.\109\
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\109\ In its Guideline 2a compliance filing in Docket No. RR08-
4-004 currently before the Commission, NERC proposes to assign the
single violation severity level for binary Requirements to the
``severe'' category.
---------------------------------------------------------------------------
2. Requirement R2
102. Requirement R2 states that transmission owners, generator
owners, and distribution providers that use a circuit with the
protective relays' settings determined by the practical limitations
described in sub-Requirements R1.6 through R1.9, R1.12, or R1.13 must
use the calculated circuit capability as the circuit's Facility Rating
and must obtain the agreement of the planning coordinator, transmission
operator, and reliability coordinator with the calculated circuit
capability. NERC designates the Requirement as a binary requirement and
assigns a ``lower'' violation severity level if an applicable entity
uses the criteria described in sub-Requirements R1.6 through R1.9,
R1.12, or R1.13, but evidence does not exist that the required
agreement was obtained.
Commission Proposal
103. It is the Commission's view that the violation severity level
NERC assigns to Requirement R2 does not reflect the degree or severity
of a violation of the requirement, but rather describes an outcome with
regard to determining compliance with the requirement. As discussed
previously, Guideline 3 ensures that assigned violation severity levels
are consistent with the corresponding requirement. The text of
Requirement R2 does not explicitly state that the applicable entity
have evidence of the agreement; only that agreement is obtained. While
the Commission agrees that Requirement R2 is a binary requirement, the
Commission disagrees with the text of the assigned violation severity
level as it is not consistent with the corresponding requirement, and
thus not consistent with Guideline 3. As such, the Commission proposes
that the single violation severity level assigned to Requirement R2
should be for the failure of the applicable entity that used the
described criteria to calculate circuit capability as the Facility
rating to obtain agreement on that rating with the required entities.
The Commission seeks comment on this proposal.
104. Also, the Commission points out that the single violation
severity level NERC assigns to this binary requirement appears to be
inconsistent with NERC's Guideline 2a compliance filing in Docket No.
RR08-4-004. In that docket, NERC assigns the single violation severity
level for binary requirements to the ``severe'' category. Here, it
assigns the single violation severity level to the ``lower'' category.
Consistent with Guideline 2a of the Violation Severity Level Order, the
Commission expects the single violation severity level assigned to
binary requirements to be consistent. Consequently, the Commission
proposes to direct the ERO to revise the violation severity level it
assigns to Requirement R2 to be consistent with Guideline 2a.
3. Requirement R3
105. Requirement R3 requires planning coordinators to designate
which transmission lines and transformers with low-voltage terminals
operated or connected between 100 kV and 200 kV are critical to the
reliability of the bulk electric system in order to prevent a cascade
and therefore subject to Requirement R1. Sub-Requirements R3.1 and
R3.1.1 specify that planning coordinators must have a process to
determine those facilities and that this process must consider input
from adjoining planning coordinators and
[[Page 25476]]
affected reliability coordinators. Sub-Requirements R3.2 and R3.3
require planning coordinators to maintain a list of designated
facilities and provide it to reliability coordinators, transmission
owners, generator owners, and distribution providers within 30 days of
its initial establishment, and within 30 days of any subsequent change.
NERC proposes a ``severe'' violation severity level when the applicable
entity has neither a process to determine facilities that are critical
to the reliability of the bulk-electric system nor a current list of
critical facilities, and ``moderate'' and ``high'' violation severity
levels based on the number of days that a planning coordinator is late
in providing the list to the required entities.
Commission Proposal
106. In light of the Commission's proposal to direct the ERO to
modify Requirement R3 and its sub-requirements, the Commission proposes
to direct the ERO to assign a violation severity level to the revised
Requirement R3 and its revised sub-requirements that is consistent with
the revisions and the guidelines set forth in the Violation Severity
Level Order.
Summary
107. Reliability Standard PRC-023-1 appears to be just, reasonable,
not unduly discriminatory or preferential, and in the public interest.
Accordingly, the Commission proposes to approve Reliability Standard
PRC-023-1 as mandatory and enforceable. In proposing to approve PRC-
023-1, the Commission emphasizes that (1) protective relay settings
determined and applied in accordance with its requirements must be
included in determining system performance, System Operating Limits and
Interconnection Reliability Operating Limits, and must be coordinated
with other protective relay settings as required by the applicable IRO,
TOP, and TPL Reliability Standards and (2) the proposed Reliability
Standard's requirements govern all relays subject to the proposed
Reliability Standard applied to protect, in any capacity, the
applicable facilities defined in the proposed Reliability Standard.
108. In addition, the Commission proposes to direct the ERO to
address specific concerns and revise violation risk factors and
violation severity level assignments of the Reliability Standard as
discussed above applying the guidelines set forth in the Violation Risk
Factor Order and Violation Severity Order 90 days before the effective
date of the Reliability Standard.
IV. Information Collection Statement
109. The Office of Management and Budget (OMB) regulations require
approval of certain information collection requirements imposed by
agency rules.\110\ Upon approval of a collection(s) of information, OMB
will assign an OMB control number and an expiration date. Respondents
subject to the filing requirements of this rule will not be penalized
for failing to respond to these collections of information unless the
collections of information display a valid OMB control number. The
Paperwork Reduction Act (PRA) \111\ requires each federal agency to
seek and obtain OMB approval before undertaking a collection of
information directed to ten or more persons, or continuing a collection
for which OMB approval and validity of the control number are about to
expire.\112\
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\110\ 5 CFR 1320.11.
\111\ 44 U.S.C. 3501-20.
\112\ 44 U.S.C. 3502(3)(A)(i), 44 U.S.C. 3507(a)(3).
---------------------------------------------------------------------------
110. The Commission is submitting these reporting and recordkeeping
requirements to OMB for its review and approval under section 3507(d)
of the PRA. Comments are solicited on the Commission's need for this
information, whether the information will have practical utility, the
accuracy of provided burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected, and any
suggested methods for minimizing the respondent's burden, including the
use of automated information techniques.
111. This NOPR proposes to approve one new Reliability Standard
developed by NERC as the ERO. Section 215 of the FPA authorizes the ERO
to develop Reliability Standards to provide for the operation of the
Bulk-Power System. Pursuant to the statute, the ERO must submit to the
Commission for approval each Reliability Standard that it proposes to
be made effective.\113\
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\113\ See 16 U.S.C. 824o(d).
---------------------------------------------------------------------------
112. Proposed Reliability Standard PRC-023-1 does not require
responsible entities to file information with the Commission. However,
the Reliability Standard requires applicable entities to develop and
maintain certain information, subject to audit by a Regional Entity. In
particular, transmission owners, generator owners and distribution
providers must ``have evidence'' to show that each of its transmission
relays are set according to the one of the criteria in Requirement R1
of the Reliability Standard.\114\ In certain circumstances set forth in
the Reliability Standard, transmission owners, generator owners and
distribution providers must have evidence that a facility rating was
agreed to by the relevant planning authority, transmission operator and
reliability coordinator.\115\ Further, planning coordinators must have
(1) a documented process for the determination of facilities that are
critical to bulk electric system reliability and (2) a current list of
such facilities.
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\114\ See Reliability Standard PRC-023-1, Measure M1.
\115\ Id., Measure M2.
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113. Public Reporting Burden: Our estimate below regarding the
number of respondents is based on the NERC compliance registry as of
March 3, 2009 and NERC's July 30, 2008 Petition that is the subject of
this proceeding. According to the NERC compliance registry, as of March
3, 2009, NERC has registered 568 distribution providers, 825 generator
owners and 324 transmission owners. Further, NERC has registered 79
planning authorities. However, the Reliability Standard does not apply
to all transmission owners, generator owners and distribution
providers. Rather, the Reliability Standard applies to transmission
owners, generator owners and distribution providers with load-response
phase protection systems applied to transmission lines operated at 200
kV and above--and other criteria set forth in the Applicability section
of the Standard, and as described in Attachment A of the Standard.
Further, some entities are registered for multiple functions, so there
is some overlap between the entities registered as distribution
providers, transmission owners, and generator owners. Given these
additional parameters, the Commission estimates that the Public
Reporting burden for the requirements contained in the NOPR is as
follows:
[[Page 25477]]
----------------------------------------------------------------------------------------------------------------
Number of Number of Hours per
Data collection respondents responses respondent Total annual hours
----------------------------------------------------------------------------------------------------------------
FERC-725G
M1--TOs, GOs and DPs must 450 1 Reporting: 0..... Reporting: 0.
``have evidence'' to show Recordkeeping: Recordkeeping: 45,000.
that each of its transmission 100.
relays are set according to
Requirement R1.
M2--Certain TOs, GOs and DPs 166 1 Reporting: 0..... Reporting: 0.
must have evidence that a Recordkeeping: 10 Recordkeeping: 1,660.
facility rating was agreed to
by PA, TOP and RC.
M3--PC must document process 79 1 175.............. 13,825.
for determining critical
facilities and (2) a current
list of such facilities.
---------------------------------------------------------------------------------
Total..................... .............. .............. ................. 60,485.
----------------------------------------------------------------------------------------------------------------
Total Annual hours for Collection: (Reporting +
recordkeeping) = 60,485 hours. Information Collection Costs: The
Commission seeks comments on the costs to comply with these
requirements. It has projected the average annualized cost to be the
total annual hours.
Recordkeeping = 60,485 @ $40/hour = $--241,940 ---- .
Labor (file/record clerk @ $17 an hour + supervisory @ $23 an hour)
Total costs = $--241,940 ---- .
Title: FERC-725-G Mandatory Reliability Standard for
Transmission Relay Loadability.
Action: Proposed Collection of Information.
OMB Control No: [To be determined.]
Respondents: Business or other for profit, and/or not for
profit institutions.
Frequency of Responses: On Occasion
Necessity of the Information: The Transmission Relay
Loadability Reliability Standard, if adopted, would implement the
Congressional mandate of the Energy Policy Act of 2005 to develop
mandatory and enforceable Reliability Standards to better ensure the
reliability of the nation's Bulk-Power System. Specifically, the
proposed Reliability Standard would ensure that protective relays are
set according to specific criteria to ensure that relays reliably
detect and protect the electric network from all fault conditions, but
do not limit transmission loadability or interfere with system
operator's ability to protect system reliability.
Internal review: The Commission has reviewed the
requirements pertaining to the proposed Reliability Standard for the
Bulk-Power System and determined that the proposed requirements are
necessary to meet the statutory provisions of the Energy Policy Act of
2005. These requirements conform to the Commission's plan for efficient
information collection, communication and management within the energy
industry. The Commission has assured itself, by means of internal
review, that there is specific, objective support for the burden
estimates associated with the information requirements.
114. Interested persons may obtain information on the reporting
requirements by contacting: Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426 [Attention: Michael Miller,
Office of the Executive Director, Phone: (202) 502-8415, fax: (202)
273-0873, e-mail: michael.miller@ferc.gov]. Comments on the
requirements of the proposed rule may also be sent to the Office of
Information and Regulatory Affairs, Office of Management and Budget,
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy
Regulatory Commission], e-mail: oira_submission@omb.eop.gov.
V. Environmental Analysis
115. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\116\ The
Commission has categorically excluded certain actions from this
requirement as not having a significant effect on the human
environment. The actions proposed here fall within the categorical
exclusion in the Commission's regulations for rules that are
clarifying, corrective or procedural, for information gathering,
analysis, and dissemination.\117\ Accordingly, neither an environmental
impact statement nor environmental assessment is required.
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\116\ Order No. 486, Regulations Implementing the National
Environmental Policy Act, 52 FR 47,897 (Dec. 17, 1987), FERC Stats.
& Regs. ] 30,783 (1987).
\117\ 18 CFR 380.4(a)(5) (2008).
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VI. Regulatory Flexibility Act Analysis
116. The Regulatory Flexibility Act of 1980 (RFA) \118\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
Most of the entities, i.e., transmission owners, generator owners,
distribution providers, and ``planning coordinators,'' or alternatively
``planning authorities,'' to which the requirements of this rule would
apply do not fall within the definition of small entities.\119\
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\118\ 5 U.S.C. 601-12.
\119\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act (SBA), which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. See
15 U.S.C. 632 (2006). According to the SBA, a small electric utility
is defined as one that has a total electric output of less than four
million MWh in the preceding year.
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117. As indicated above, based on available information regarding
NERC's compliance registry, approximately 525 entities will be
responsible for compliance with the new Reliability Standard. The
Commission certifies that the proposed Reliability Standard will not
have a significant adverse impact on a substantial number of small
entities.
118. Based on this understanding, the Commission certifies that
this rule will not have a significant economic impact on a substantial
number of small entities. Accordingly, no regulatory flexibility
analysis is required.
VII. Comment Procedures
119. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due July 27, 2009. Comments must
refer to Docket No. RM08-13-000, and must include the commenter's name,
the organization they represent, if applicable, and their address in
their comments.
120. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://
www.ferc.gov. The Commission accepts most standard word processing
formats. Documents
[[Page 25478]]
created electronically using word processing software should be filed
in native applications or print-to-PDF format and not in a scanned
format. Commenters filing electronically do not need to make a paper
filing.
121. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
122. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.
VIII. Document Availability
123. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
124. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
125. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
public.referenceroom@ferc.gov.
List of Subjects in 18 CFR Part 40
Electric power, Reporting and recordkeeping requirements.
By direction of the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. E9-12350 Filed 5-27-09; 8:45 am]
BILLING CODE 6717-01-P