Transmission Relay Loadability Reliability Standard, 25461-25478 [E9-12350]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 74, Number 101 (Thursday, May 28, 2009)]
[Proposed Rules]
[Pages 25461-25478]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-12350]


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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: https://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 https://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.
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    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.
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    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.
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    \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.
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    \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).
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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.
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    \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.
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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\
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    \59\ NERC Petition at 19, 41.
    \60\ Id. at 19.
    \61\ Id. at 23.
    \62\ Id.
    \63\ Id.
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    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.
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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.
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    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.
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    \67\ NERC Report at 13.
    \68\ Final Blackout Report at 158.
    \69\ NERC Petition at 23.
    \70\ Id.
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    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.
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    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.
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    \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 wit