[Federal Register Volume 75, Number 63 (Friday, April 2, 2010)]
[Rules and Regulations]
[Pages 16914-16956]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-6568]
[[Page 16913]]
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Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 40
Transmission Relay Loadability Reliability Standard; Final Rule
Federal Register / Vol. 75 , No. 63 / Friday, April 2, 2010 / Rules
and Regulations
[[Page 16914]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM08-13-000; Order No. 733]
Transmission Relay Loadability Reliability Standard
March 18, 2010.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final rule.
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SUMMARY: Pursuant to section 215 of the Federal Power Act, the Federal
Energy Regulatory Commission approves the Transmission Relay
Loadability Reliability Standard (PRC-023-1), developed by the North
American Electric Reliability Corporation (NERC). Reliability Standard
PRC-023-1 requires transmission owners, generator owners, and
distribution providers to set load-responsive phase protection 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. In addition,
pursuant to section 215(d)(5) of the Federal Power Act, the Commission
directs NERC to develop modifications to the Reliability Standard to
address specific concerns identified by the Commission.
DATES: Effective Date: This rule will become effective May 17, 2010.
FOR FURTHER INFORMATION CONTACT:
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.
Joshua Konecni (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426. (202) 502-6291.
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
Nos.
I. Background............................................... 2
II. Reliability Standard PRC-023-1.......................... 5
A. Applicability........................................ 6
B. Requirements......................................... 8
1. Requirement R1................................... 9
2. Requirement R2................................... 10
3. Requirement R3................................... 11
III. Discussion............................................. 12
A. Overview............................................. 12
B. Approval of PRC-023-1................................ 13
C. Applicability........................................ 20
D. Generator Step-Up and Auxiliary Transformers......... 98
1. Omission From the Reliability Standard........... 98
2. Generator Step-Up Transformer Relays as Back-up 109
Protection.........................................
E. Need to Address Additional Issues.................... 115
1. Zone 3/Zone 2 Relays Applied as Remote Circuit 116
Breaker Failure and Backup Protection..............
2. Protective Relays Operating Unnecessarily due to 130
Stable Power Swings................................
F. Requirement R1....................................... 174
1. Sub-Requirement R1.1............................. 175
2. Sub-Requirement R1.2............................. 178
3. Sub-Requirement R1.10............................ 190
4. Sub-Requirement R1.12............................ 213
G. Requirement R2....................................... 227
H. Requirement R3 and Its Sub-Requirements.............. 230
1. Role of the Planning Coordinator................. 231
2. Sub-Requirement R3.3............................. 235
I. Attachment A......................................... 238
1. Section 2: Evaluation of Out-of-Step Blocking 239
Schemes............................................
2. Section 3: Protection Systems Excluded from the 249
Reliability Standard...............................
J. Effective Date....................................... 273
K. Violation Risk Factors............................... 285
L. Violation Severity Levels............................ 298
M. Miscellaneous........................................ 313
1. Purpose of the Reliability Standard.............. 313
2. Transmission Facility Design Margin.............. 316
IV. Information Collection Statement........................ 318
V. Environmental Analysis................................... 329
VI. Regulatory Flexibility Act.............................. 330
VII. Document Availability.................................. 345
VIII. Effective Date and Congressional Notification......... 348
Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer,
Philip D. Moeller, and John R. Norris.
1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Commission approves the Transmission Relay Loadability Reliability
Standard (PRC-023-1), developed by the North American Electric
Reliability Corporation (NERC) in its capacity as the Electric
Reliability Organization
[[Page 16915]]
(ERO).\2\ Reliability Standard PRC-023-1 requires transmission owners,
generator owners, and distribution providers to set load-responsive
phase protection 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.\3\ In addition, pursuant to section 215(d)(5) of the
FPA,\4\ the Commission directs the ERO to develop modifications to PRC-
023-1 to address specific concerns identified by the Commission and
sets specific deadlines for these modifications.
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\1\ 16 U.S.C. 824o. The Commission is not adding any new or
modified text to its regulations.
\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, 564 F.3d 1342 (DC Cir. 2009).
\3\ Loadability refers to the ability of protective relays to
refrain from operating under load conditions.
\4\ 16 U.S.C. 824o(d)(5).
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I. Background
2. Protective relays are devices that detect and initiate the
removal of faults on an electric system.\5\ They are designed to read
electrical measurements, such as current, voltage, and frequency, and
can be set to recognize certain measurements as indicating a fault.
When a protective relay detects a fault on an element of the system
under its protection, it sends a signal to an interrupting device(s)
(such as a circuit breaker) to disconnect the element from the rest of
the system.\6\ Impedance relays (also known as distance relays) are the
most common type of load-responsive phase protection relays used to
protect transmission lines. Impedance relays can also provide backup
protection and protection against remote circuit breaker failure.
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\5\ Protective relays are one type of equipment used in
protection systems. The NERC definition of protection systems also
includes communication systems associated with protective relays,
voltage and current sensing devices, station batteries, and DC
control circuitry. See NERC Glossary of Terms Used in Reliability
Standards at 14.
\6\ Coordination of protection through distance settings and
time delays ensures that the relay closest to a fault operates
before a relay farther away from the fault, thereby ensuring that
the more distant relay does not disconnect both the transmission
equipment necessary to remove the fault and ``healthy'' equipment
that should remain in service.
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3. Following the August 2003 blackout that affected parts of the
Midwest and Northeast United States, and Ontario, Canada, NERC and the
U.S.-Canada Power System Outage Task Force (Task Force) concluded that
a substantial number of transmission lines disconnected during the
blackout when load-responsive phase-protection backup distance and
phase relays operated unnecessarily, i.e. under non-fault conditions.
Although these relays operated according to their settings, the Task
Force determined that the operation of these relays for non-fault
conditions contributed to cascading outages at the start of the
blackout and accelerated the geographic spread of the cascade.\7\
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\7\ 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, at 80 (2004) (Final Blackout Report).
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4. Seeking to prevent or minimize the scope of future blackouts,
both NERC and the Task Force made recommendations to ensure that these
types of protective relays do not contribute to future blackouts.
Recommendation 8A of the NERC Report addresses the need to evaluate
load-responsive protection zone 3 relays \8\ to determine whether they
will operate under extreme emergency conditions:
\8\ Multiple impedance relays are installed at each end of a
transmission line, with each used to protect a certain percentage,
or zone, of the local transmission line and remote lines. 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 and more than 100 percent of the longest
line (including any series elements such as transformers) that
emanates from the remote buses.
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
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system.\9\
\9\ August 14, 2003 Blackout: NERC Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts, at 13 (2004)
(NERC Report).
Recommendation No. 21A of the Task Force Final Blackout Report (Final
Blackout Report) urges NERC to expand the scope of its review to
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include certain operationally significant facilities:
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].\10\
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\10\ Final Blackout Report at 158.
In its petition, NERC states that PRC-023-1 is intended to
specifically address these recommendations.
II. Reliability Standard PRC-023-1
5. Reliability Standard PRC-023-1 requires transmission owners,
generator owners, and distribution providers to set load-responsive
phase protection 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 operate during non-fault load
conditions.
A. Applicability
6. As proposed by NERC, the Reliability Standard applies to relay
settings on: (1) All transmission lines and transformers with low-
voltage terminals operated or connected at or above 200 kV; \11\ and
(2) those transmission lines and transformers with low-voltage
terminals operated or connected between 100 kV and 200 kV \12\ that are
designated by planning coordinators as critical to the reliability of
the bulk electric system.\13\
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\11\ NERC 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. 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. NERC Petition at 18-19, 39-41.
\12\ In this Final Rule, we occasionally use the shorthand ``100
kV-200 kV facilities'' to refer to transmission lines and
transformers with low-voltage terminals operated or connected
between 100 kV and 200 kV.
\13\ In this Final Rule, we use the terms ``bulk electric
system'' and ``Bulk-Power System.'' ``Bulk electric system'' is
defined in the NERC Glossary of Terms Used in Reliability Standards,
and generally includes facilities operated at voltages at and above
100 kV. See NERC Glossary of Terms Used in Reliability Standards at
2. ``Bulk-Power System'' is defined in section 215 of the FPA, and
does not include a voltage threshold. See 16 U.S.C. 824o(a)(1). In
Order No. 693, the Commission explained that while it would rely on
the NERC definition of bulk electric system during the start-up
phase of the mandatory Reliability Standard regime, the statutory
Bulk-Power System encompasses more facilities than are included in
NERC's definition of the bulk electric system. Mandatory Reliability
Standards for the Bulk-Power System, Order No. 693, FERC Stats. &
Regs. ] 31,242, at P 75-76; order on reh'g, Order No. 693-A, 120
FERC ] 61,053 (2007).
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[[Page 16916]]
7. Attachment A to the Reliability Standard specifies which
protection systems are subject to and excluded from the Standard's
Requirements. Section 1 of Attachment A provides that the Reliability
Standard applies to any protective functions that can operate with or
without time delay, on load current, including but not limited to: (1)
Phase distance; (2) out-of-step tripping; (3) switch-on-to-fault; (4)
overcurrent relays; and (5) communication-aided protection
applications.\14\ Section 2 states that the Reliability Standard
requires evaluation of out-of-step blocking schemes \15\ to ensure that
they do not operate for faults during the loading conditions defined in
the Standard's Requirements. Finally, section 3 expressly excludes from
the Reliability Standard's Requirements: (1) 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); (2) protection relay systems intended for the
detection of ground fault conditions or for protection during stable
power swings; (3) generator protection relays susceptible to load; (4)
relay elements used only for special protection systems applied and
approved in accordance with Reliability Standards PRC-012 through PRC-
017; \16\ (5) protection relay systems designed to respond only in time
periods that allow operators 15 minutes or longer to respond to
overload conditions; (6) thermal emulation relays used in conjunction
with dynamic facility ratings; (7) relay elements associated with DC
line; and (8) relay elements associated with DC converter transformers.
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\14\ Section 1.5 specifies that the communications aided
applications subject to the Reliability Standard include, but are
not limited to: (1) Permissive overreach transfer trip; (2)
permissive under-reach transfer trip; (3) directional comparison
blocking; and (4) directional comparison unblocking.
\15\ ``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.
\16\ The Commission has not yet acted on PRC-012-0, PRC-013-0,
or PRC-014-0 because it is awaiting further information from the
ERO.
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B. Requirements
8. Reliability Standard PRC-023-1 consists of three Requirements.
Requirement R1 directs entities to set their relays according to one of
the options set forth in sub-requirements R1.1 through R1.13.
Requirement R2 contains directives for entities that set their relays
according to sub-requirements R1.6 through R1.9, R1.12, or R1.13.
Requirement R3 directs planning coordinators to designate which
facilities operated between 100 kV and 200 kV are critical to the
reliability of the bulk electric system and therefore must have their
relays set according to one of the options in Requirement R1.
1. Requirement R1
9. Requirement R1 directs entities to set their relays according to
one of thirteen specific settings (sub-requirements R1.1 through R1.13)
intended to maximize loadability while maintaining Reliable Operation
of the bulk electric system for all fault conditions. Entities must
evaluate relay loadability at 0.85 per unit voltage and a power factor
angle of 30 degrees and set their transmission line relays so that they
do not operate:
R1.1. [A]t or below 150 [percent] of the highest seasonal
[f]acility [r]ating of a circuit, for the available defined loading
duration nearest 4 hours (expressed in amperes)[;]
R1.2. [A]t or below 115 [percent] of the highest seasonal 15-
minute [f]acility [r]atingof a circuit (expressed in amperes)[;]
\17\
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\17\ NERC includes a footnote that states ``[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.''
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R1.3. [A]t or below 115 [percent] of the maximum theoretical
power transfer capability (using a 90-degree angle between the
sending-end and receiving-end voltages and either reactance or
complex impedance) of the circuit (expressed in amperes) using one
of the following to perform the power transfer calculation:
R1.3.1. An infinite source (zero source impedance) with a 1.00
per unit bus voltage at each end of the line[;] [or]
R1.3.2. 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[;]
R1.4. [O]n series compensated transmission lines[,] * * * at or
below the maximum power transfer capability of the line, determined
as the greater of:
[a.] 115 [percent] of the highest emergency rating of the series
capacitor[;] [or]
[b.] 115 [percent] of the maximum power transfer capability of
the circuit (expressed in amperes), calculated in accordance with
R1.3, using the full line inductive reactance[;]
R1.5. [O]n weak source systems[,] * * * at or below 170
[percent] of the maximum end-of-line three-phase fault magnitude
(expressed in amperes)[;]
R1.6. [On] transmission line relays applied on transmission
lines connected to generation stations remote to load[,] * * * at or
below 230 [percent] of the aggregated generation nameplate
capability[;]
R1.7. [On] transmission line relays applied at the load center
terminal, remote from generation stations, * * * at or below 115
[percent] of the maximum current flow from the load to the
generation source under any system configuration[;]
R1.8. [On] transmission line relays applied on the bulk system-
end of transmission lines that serve load remote to the system[,] *
* * at or below 115 [percent] of the maximum current flow from the
system to the load under any system configuration[;]
R1.9. [On] transmission line relays applied on the load-end of
transmission lines that serve load remote to the bulk system[,] * *
* at or below 115 [percent] of the maximum current flow from the
load to the system under any system configuration[;]
R1.10. [On] transformer fault protection relays and transmission
line relays on transmission lines terminated only with a
transformer[,] * * * at or below the greater of:
[a.] 150 [percent] of the applicable maximum transformer
nameplate rating (expressed in amperes), including the forced cooled
ratings corresponding to all installed supplemental cooling
equipment[;] [or]
[b.] 115 [percent] of the highest operator established emergency
transformer rating[;]
R1.11. For transformer overload protection relays that do not
comply with R1.10[,] [the entity must either]. * * *
[a.] Set the relays to allow the transformer to be operated at
an overload level of at least 150 [percent] of the maximum
applicable nameplate rating, or 115 [percent] of the highest
operator established emergency transformer rating, whichever is
greater. The protection must allow this overload for at least 15
minutes to allow for the operator to take controlled action to
relieve the overload[;] [or]
[b.] Install supervision for the relays using either a top oil
or simulated winding hot spot temperature element. The setting
should be no less than 100[deg] C for the top oil or 140[deg] C for
the winding hot spot temperature[;] \18\
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\18\ NERC includes a footnote that states: ``IEEE [S]tandard
C57.115, Table 3, specifies that transformers are to be designed to
withstand a winding hot spot temperature of 180 degrees C, and
cautions that bubble formation may occur above 140 degrees C.''
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R1.12. When the desired transmission line capability is limited
by the requirement to adequately protect the transmission line, set
the transmission line distance relays to a maximum of 125 [percent]
of the apparent impedance (at the impedance angle of the
transmission line) subject to the following constraints:
R1.12.1. Set the maximum torque angle (MTA) to 90 degrees or the
highest supported by the manufacturer[;]
R1.12.2. Evaluate the relay loadability in amperes at the relay
trip point at 0.85 per unit voltage and a power factor angle of 30
degrees[;] [and]
R1.12.3. Include a relay setting component of 87 [percent] of
the current calculated in R1.12.2 in the [f]acility [r]ating
determination for the circuit[;]
R1.13. [Finally,] [w]here other situations present practical
limitations on circuit capability, [entities can] set the phase
[[Page 16917]]
protection relays so they do not operate at or below 115 [percent]
of such limitations.
2. Requirement R2
10. Requirement R2 provides that entities that set their relays
according to 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 authority over the facility
as to the calculated circuit capability.
3. Requirement R3
11. Requirement R3 directs planning coordinators to designate which
facilities operated between 100 kV and 200 kV are critical to the
reliability of the bulk electric system and therefore must have their
relays set according to one of the options in Requirement R1. Sub-
requirement R3.1 requires planning coordinators to have a process to
identify critical facilities. Sub-requirement R3.1.1 specifies that the
process must consider input from adjoining planning coordinators and
affected reliability coordinators. Sub-requirements R3.2 and R3.3
require planning coordinators to maintain a list of critical facilities
and provide it to reliability coordinators, transmission owners,
generator owners, and distribution providers within 30 days of
initially establishing it, and 30 days of any subsequent change.
III. Discussion
A. Overview
12. The Commission approves PRC-023-1, finding that it is just and
reasonable, not unduly discriminatory or preferential and in the public
interest. The Commission also directs the ERO to develop modifications
to PRC-023-1 through its Reliability Standards development process to
address specific concerns identified by the Commission and sets
specific deadlines for these modifications. Similar to our approach in
Order No. 693,\19\ we view such directives as separate from approval,
consistent with our authority under section 215(d)(5) of the FPA to
direct the ERO to develop a modification to a Reliability Standard.
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\19\ See supra n.13.
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B. Approval of PRC-023-1
1. NOPR Proposal
13. On May 21, 2009, the Commission issued a Notice of Proposed
Rulemaking (NOPR) proposing to approve PRC-023-1 as mandatory and
enforceable.\20\ As a separate action, pursuant to section 215(d)(5) of
the FPA, the Commission proposed to direct certain modifications to the
Reliability Standard.
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\20\ Transmission Relay Loadability Reliability Standard, Notice
of Proposed Rulemaking, 74 FR 35830 (Jul. 21, 2009), FERC Stats. &
Regs. ] 32,642 (2009) (NOPR).
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2. Comments
14. While commenters universally support the Commission's proposal
to approve PRC-023-1,\21\ most commenters oppose the majority of the
Commission's proposed modifications. Some commenters argue that the
Commission's proposed modifications violate Order No. 693 because they
prescribe specific changes that would dictate the content of the
modified Reliability Standard.
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\21\ See, e.g., NERC Comments, EEI, TAPS, APPA, NARUC, EPSA,
Exelon.
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3. Commission Determination
15. Pursuant to section 215(d)(2) of the FPA,\22\ the Commission
approves PRC-023-1 as just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The Commission finds that
PRC-023-1 is a significant step toward improving the reliability of the
Bulk-Power System in North America because it requires load-responsive
phase protection relay settings to provide essential facility
protection for faults, while allowing the Bulk-Power System to be
operated in accordance with established facility ratings.
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\22\ 16 U.S.C. 824o(d)(2).
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16. Also, pursuant to section 215(d)(5) of the FPA, the Commission
adopts some of the proposed modifications in the NOPR and thus directs
certain modifications to the Reliability Standard. Unless stated
otherwise, the Commission directs the ERO to submit these modifications
no later than one year from the date of this Final Rule. We will
address each proposal and the specific comments received on each
proposal in the remainder of this Final Rule.
17. With regard to the concerns raised by some commenters about the
prescriptive nature of the Commission's proposed modifications, we
agree that, consistent with Order No. 693, a direction for modification
should not be so overly prescriptive as to preclude the consideration
of viable alternatives in the ERO's Reliability Standards development
process. However, some guidance is necessary, as the Commission
explained in Order No. 693:
[I]n identifying a specific matter to be addressed in a
modification * * * it is important that the Commission provide
sufficient guidance so that the ERO has an understanding of the
Commission's concerns and an appropriate, but not necessarily
exclusive, outcome to address those concerns. Without such direction
and guidance, a Commission proposal to modify a Reliability Standard
might be so vague that the ERO would not know how to adequately
respond.\23\
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\23\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 185.
18. Thus, in some instances, while we provide specific details
regarding the Commission's expectations, we intend by doing so to
provide useful guidance to assist in the Reliability Standards
development process, not to impede it. As we explained in Order No.
693, we find that this is consistent with statutory language that
authorizes the Commission to order the ERO to submit a modification
``that addresses a specific matter'' if the Commission considers it
appropriate to carry out section 215 of the FPA.\24\ In this Final
Rule, we have considered commenters' concerns and, where a directive
for modification appears to be determinative of the outcome, the
Commission provides flexibility by directing the ERO to address the
underlying issue through the Reliability Standards development process
without mandating a specific change to PRC-023-1.\25\ Consequently,
consistent with Order No. 693, we clarify that where the Final Rule
identifies a concern and offers a specific approach to address that
concern, we will consider an equivalent alternative approach provided
that the ERO demonstrates that the alternative will adequately address
the Commission's underlying concern or goal as efficiently and
effectively as the Commission's proposal.\26\
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\24\ Id. P 186.
\25\ Id.
\26\ Id.
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19. Consistent with section 215 of the FPA, our regulations, and
Order No. 693, any modification to a Reliability Standard, including a
modification that addresses a Commission directive, must be developed
and fully vetted through NERC's Reliability Standards development
process.\27\
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\27\ Id. P 187.
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C. Applicability
20. As proposed by NERC, PRC-023-1 does not apply to any facility
operated or connected between 100 kV and 200 kV unless the relevant
planning coordinator designates the facility as ``critical'' to the
reliability of the bulk electric system. In the NOPR, the
[[Page 16918]]
Commission described this as an ``add in'' approach to
applicability.\28\
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\28\ NOPR, FERC Stats. & Regs. ] 32,642 at P 40.
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21. Requirement R3 of PRC-023-1 directs planning coordinators to
determine which 100 kV-200 kV facilities are critical to the
reliability of the bulk electric system, and therefore subject to the
Reliability Standard; it does not, however, define ``critical to the
reliability of the bulk electric system'' or provide planning
coordinators with a test to identify critical facilities.
1. NOPR Proposal
22. In the NOPR, the Commission stated that it expects planning
coordinators to use a process to carry out Requirement R3 that is
consistent across regions and robust enough to identify all facilities
that should be subject to PRC-023-1. The Commission expressed concern
that, based on the information in NERC's petition, the ``add in''
approach proposed by NERC would fail to meet these expectations.
23. The Commission explained that since approximately 85 percent of
circuit miles of electric transmission are operated at or below 253 kV,
the ``add in'' approach could, at the outset, effectively exempt from
the Reliability Standard's requirements a large percentage of
facilities that should otherwise be subject to the Standard. The
Commission also cited a letter from NERC to industry stakeholders
discussing the results of an ``add in'' approach in the context of
industry's self-identification of Critical Cyber Assets. According to
the Commission, the letter was an acknowledgement from NERC that the
``add in'' approach failed to produce a comprehensive list of Critical
Cyber Assets.\29\ The Commission further observed that NERC failed to
provide a technical basis for the ``add in'' approach, and did not
support its claim that expanded application of PRC-023-1 would double
implementation costs and distract industry resources from more
important areas. The Commission added that PRC-023-1 was developed to
prevent cascading outages, and that no area has a greater impact on the
reliability of the bulk electric system than the prevention of
cascading outages.
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\29\ Id.
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24. The Commission emphasized that PRC-023-1 must apply to relay
settings on all critical facilities for it to achieve its intended
reliability objective.\30\ In order to meet this goal, the Commission
stated that the process for identifying critical 100 kV-200 kV
facilities must include the same system simulations and assessments as
the Transmission Planning (TPL) Reliability Standards for reliable
operation for all categories of contingencies used in transmission
planning for all operating conditions. The Commission also stated that
it expects a comprehensive review to identify nearly every 100 kV-200
kV facility as a critical facility. In light of this expectation, and
coupled with its concern about the ``add in'' approach, the Commission
proposed to direct the ERO to adopt a ``rule out'' approach to
applicability; that is, to modify PRC-023-1 so that it applies to relay
settings on all 100 kV-200 kV facilities, with the possibility of case-
by-case exceptions for facilities that are not critical to the
reliability of the bulk electric system and demonstrably would not
result in cascading outages, instability, uncontrolled separation,
violation of facility ratings, or interruption of firm transmission
service.\31\
---------------------------------------------------------------------------
\30\ Id. P 42.
\31\ Id. P 43.
---------------------------------------------------------------------------
25. Finally, the Commission proposed to direct the ERO to adopt an
``add in'' approach to sub-100 kV facilities that Regional Entities
have identified as critical to the reliability of the bulk electric
system.\32\ The Commission explained that owners and operators of such
facilities are defined as transmission owners/operators for the
purposes of NERC's Compliance Registry,\33\ and that sub-100 kV
facilities can be included in regional definitions of the bulk electric
system.\34\ The Commission also stated that NERC failed to provide a
sufficient technical record to justify excluding such facilities from
the scope of the Reliability Standard.
---------------------------------------------------------------------------
\32\ Id. P 45.
\33\ NERC's Compliance Registry is a listing of organizations
subject to compliance with mandatory Reliability Standards. See NERC
Rules of Procedure, Section 500. NERC's Statement of Compliance
Registry Criteria, which sets forth thresholds for registration,
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.
See NERC Statement of Compliance Registry Criteria at 9.
\34\ NERC defines the bulk electric system as follows:
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.
See NERC Glossary of Terms Used in Reliability Standards at 2.
---------------------------------------------------------------------------
2. Comments
26. In response to the NOPR, the Commission received comments
addressing its remarks about the test that planning coordinators must
use to implement Requirement R3 and its proposals to direct the ERO to
adopt the ``rule out'' approach for 100 kV-200 kV facilities and the
``add in'' approach for sub-100 kV facilities.
a. Comments on the Test That Planning Coordinators Must Use To
Implement Requirement R3
27. Commenters generally agree with the Commission that the process
for identifying critical facilities pursuant to Requirement R3 should
include the same simulation and assessments required by the TPL
Reliability Standards for all operating conditions. However, commenters
disagree with the Commission's expectation that planning coordinators
will identify nearly every 100 kV-200 kV facility as a critical
facility. For example, Duke reports that it has applied the existing
TPL standards to its Midwest and Carolina systems and has not
identified any sub-200 kV facility as a critical facility (i.e., there
have been no showings that the loss of any such facilities could result
in cascading outages, instability, or uncontrolled separation). Other
commenters maintain that the Commission's expectation is not supported
by any technical evidence and depends on a circular definition between
``above 100 kV'' and ``critical to the reliability of the bulk electric
system.'' \35\
---------------------------------------------------------------------------
\35\ See, e.g., Basin, Exelon, and WECC.
---------------------------------------------------------------------------
28. NERC recognizes the need for consistent criteria across North
America for identifying critical 100 kV-200 kV facilities and proposes
to work through industry to develop it.\36\ Although NERC did not
propose a test in PRC-023-1, in its comments it did provide the
suggestions for identifying operationally significant 100 kV-200 kV
facilities that the NERC System Protection and Control Task Force
provided to Regional Entities in 2004 and 2005 during the voluntary
Beyond Zone 3 relay review and mitigation program.\37\ During that
program, NERC suggested that Regional Entities identify:
---------------------------------------------------------------------------
\36\ NERC Comments at 12.
\37\ For a discussion of the Beyond Zone 3 relay review and
mitigation program, see infra P 34.
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All circuits that are elements of flowgates[\38\] in the Eastern
Interconnection,
[[Page 16919]]
Commercially Significant Constraints in the Texas Interconnection,
or Rated Paths in the Western Interconnection. This includes both
the monitored and outage element for OTDF [Outage Transfer
Distribution Factor] sets.[\39\]
---------------------------------------------------------------------------
\38\ A ``flowgate'' is a single or group of transmission
elements intended to model MW flow impact relating to transmission
limitations and transmission service outage. See Final Black Report
at 214. Flowgates are operationally significant for the purpose of
ensuring desirable system performance because an actual outage would
present the modeled physical limitations on the bulk electric
system.
\39\ In the post-contingency configuration of a system under
study, Outage Transfer Distribution Factor refers to the measure of
the responsiveness or change (expressed in percent) in electrical
loadings on transmission system facilities due to a change in
electric power transfer from one area to another with one or more
system facilities removed from service.
---------------------------------------------------------------------------
All circuits that are elements of system operating limits (SOLs)
and interconnection reliability operating limits (IROLs), including
both monitored and outage elements.
All circuits that are directly related to off-site power supply
to nuclear plants. Any circuit whose outage causes unacceptable
voltages on the off-site power bus at a nuclear plant must be
included, regardless of its proximity to the plant.
All circuits of the first 5 limiting elements (monitored and
outaged elements) for transfer interfaces[\40\] determined by
regional and interregional transmission reliability studies. If
fewer than 5 limiting elements are found before reaching studied
transfers, all should be listed.
---------------------------------------------------------------------------
\40\ An ``interface'' is the specific set of transmission
elements between two areas or between two areas comprising one or
more electrical systems. See Final Blackout Report at 215. An
interface is operationally significant for the purpose of ensuring
desirable system performance because an outage of an interface would
affect IROLs.
---------------------------------------------------------------------------
Other circuits determined and agreed to by the reliability
authority/coordinator and the Regional Reliability Organizations.
29. In its comments, APPA proposes that the Commission direct NERC
to develop a process whereby each region can develop a specific
methodology to ensure consistent, verifiable identification of critical
facilities.
b. Comments on the ``Rule Out'' Approach
30. Commenters unanimously oppose the ``rule out'' approach. In
general, they argue that it is unnecessary, extremely costly, and
potentially detrimental to reliability.
31. NERC, EEI, and WECC argue that the cascade of 138 kV lines that
occurred during the August 2003 blackout would not have occurred if the
345 kV lines in their vicinity had not tripped, and that the 345 kV
lines would not have tripped if PRC-023-1 had been in effect prior to
the blackout.\41\ EEI, PG&E, and SRP add that whenever a facility
between 100 kV and 200 kV trips on load, it is almost always because of
preceding faults at higher voltages.
---------------------------------------------------------------------------
\41\ See, e.g., NERC Comments at 10, 16.
---------------------------------------------------------------------------
32. Some commenters argue that the majority of facilities between
100 kV and 200 kV are not critical to the reliability of the bulk
electric system and are unlikely to contribute to cascading outages at
higher voltages. APPA, EEI, and WECC state that most wide-area bulk
power transfers flow on high voltage facilities, while most sub-200 kV
facilities support local distribution service.\42\ SRP asserts that a
malfunction on a 100 kV-200 kV line typically causes an outage only for
the load connected to the faulted part of the line, leaving the rest of
the line unaffected; PG&E makes the related claim that the tripping of
a 100 kV-200 kV facility generally has a low impact on the reliability
of higher voltage systems, even when the two systems run in parallel.
APPA argues that cascading outages at higher voltages are unlikely to
be arrested by relay action at lower voltages. EEI adds that many 100
kV-200 kV facilities are designed to support local distribution service
and their related protection systems are set to ensure separation,
including load shedding, if disturbances or system events take place.
EEI asserts that these systems ensure ``controlled separation'' that,
by definition, does not involve the Bulk-Power System.
---------------------------------------------------------------------------
\42\ SRP and Y-WEA emphasize that this is especially true in the
western interconnection, where sub-200 kV facilities are generally
used as localized means for distributing electricity to moderately
sized and geographically distant load centers. See also
ElectriCities and NWCP.
---------------------------------------------------------------------------
33. Commenters also argue that the ``rule out'' approach is a
costly and inefficient use of limited industry resources that will
place an unreasonable burden on small entities and require utilities to
incur unnecessary upfront costs, forego other important initiatives,
and direct money and personnel away from the work necessary to ensure
the day-to-day reliability of the bulk electric system.
34. NERC states that it modeled PRC-023-1 on two post-blackout
relay review and mitigation programs (the Zone 3 Review and Beyond Zone
3 Review) that focused primarily on facilities operated at or above 200
kV, and that these programs give it a basis for concluding that the
costs of the ``rule out'' approach are extremely high.\43\ NERC reports
that these programs took over three years to complete, required close
to 150,000 hours of labor, cost almost $18 million, and resulted in
mitigation costs (equipment change-outs or additions) of approximately
$65 million, or $111,500 per terminal. Based on a survey of industry
conducted after the NOPR, NERC estimates that a review and mitigation
program for all facilities between 100 kV and 200 kV would far exceed
these costs in time and money. NERC estimates that such a program would
entail review of approximately 53,000 terminals, require close to
340,000 hours of labor, and cost almost $41 million.\44\ Based on the
results of the previous review programs, NERC estimates that at least
11,400 terminals could be out-of-compliance and that mitigation could
take between 5 and 10 years and cost approximately $590 million.\45\ In
contrast, NERC estimates that the ``add in'' approach would entail
review of only 2,400 terminals and require mitigation for approximately
500, roughly 240 of which would require equipment replacement.\46\
---------------------------------------------------------------------------
\43\ The Zone 3 Review examined 10,914 terminals operating at or
above 200 kV. The Beyond Zone 3 Review examined 12,273 terminals
operating at or above 200 kV and operationally significant terminals
operating between 100 kV and 200 kV. NERC Comments at 9-16.
\44\ Id. at 13-14. NERC adds that 114 transmission owners
operating 100 kV-200 kV lines responded to the survey.
\45\ Id. at 14.
\46\ Id. at 15.
---------------------------------------------------------------------------
35. Some commenters argue that the ``rule out'' approach may
adversely affect reliability. Exelon is concerned that the ``rule out''
approach may unintentionally result in the over-inclusion of facilities
subject to PRC-023-1. Exelon believes that such over-inclusion will
take a known and successful backup protection scheme and make it less
effective. Exelon explains that over-inclusion will increase the risk
of certain instances of backup relaying not tripping when it should,
thus allowing what would otherwise be a minor disturbance to expand
unnecessarily.\47\ Consumers Energy and Entergy argue that the ``rule
out'' approach will require entities to divert scarce resources from
other duties that are essential to reliability, thereby adversely
affecting reliability. Basin argues that the complexity of integrating
PRC-023-1 with other Reliability Standards for lower voltage lines will
divert personnel from more important aspects of the Reliability
Standards and adversely affect reliability.
---------------------------------------------------------------------------
\47\ See also Ameren at 8.
---------------------------------------------------------------------------
36. In addition to these arguments, commenters oppose the ``rule
out'' approach on the grounds that it: (1) Fails to give due weight to
the technical expertise of the ERO, as required by section 215(d)(2) of
the FPA; (2) violates Order No. 693 because it prescribes a specific
change that will dictate the content of the modified Reliability
[[Page 16920]]
Standard; \48\ (3) is inconsistent with the Commission's statements in
Order No. 672 about the cost of Reliability Standards; \49\ (4) rests
on the unsupported assumption that planning coordinators will fail to
produce a comprehensive list of critical facilities; and (5)
mischaracterizes NERC's letter expressing concern about the use of an
``add in'' approach in the Critical Cyber Assets survey.\50\
---------------------------------------------------------------------------
\48\ See e.g., TAPS, APPA, EEI, Ameren, Manitoba Hydro, Georgia
Transmission, Tri-State, CRC, EEI, APPA, Ameren, TANC, Fayetteville
Public Works Commission, and LES.
\49\ In Order No. 672, the Commission stated that ``[a] proposed
Reliability Standard does not necessarily have to reflect the
optimal method, or `best practice,' for achieving its reliability
goal without regard to implementation cost. * * * [but] should[,]
however[,] achieve its reliability goal effectively and
efficiently;'' Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment,
Approval, and Enforcement of Electric Reliability Standards, Order
No. 672, FERC Stats. & Regs. ] 31,204, at P 328, order on reh'g,
Order No. 672-A, FERC Stats. & Regs. ] 31,212 (2006).
\50\ See e.g., Exelon, PG&E, EEI, Basin, and TAPS.
---------------------------------------------------------------------------
37. In the event that the Commission adopts the ``rule out''
approach, commenters argue that the Commission should immediately
confirm the following exclusions: (1) Facilities that are not part of a
defined and routinely monitored flowgate; (2) radial transmission
lines, because they are specifically excluded from the bulk electric
system and are not critical to the reliability of the bulk electric
system; \51\ and (3) Category D Contingencies, because they involve the
loss of multiple transmission facilities caused by the outage of
transmission facilities other than those relevant to the Reliability
Standard.
---------------------------------------------------------------------------
\51\ See e.g., ElectriCities, NWCP, Palo Alto, PSEG Companies,
Pacific Northwest State Commissions, Y-WEA, and Filing Cooperatives.
---------------------------------------------------------------------------
38. Commenters also disagree with what they describe as the
Commission's 5-part test for case-by-case exceptions from the ``rule
out'' approach, that is, its proposal to permit exceptions for
facilities that demonstrably would not result in: (1) Cascading
outages; (2) instability; (3) uncontrolled separation; (4) violation of
facility ratings; or (5) interruption of firm transmission service.
39. At the outset, commenters assert that they do not understand
the relationship between the 5-part test for exceptions from the ``rule
out'' approach and the Commission's insistence that the ``add in''
process must include the same simulations and assessments as the TPL
Reliability Standards. Commenters are unsure whether the 5-part test is
in addition to, or in lieu of, the TPL assessments.
40. Commenters also challenge the substance of the 5-part test,
generally arguing that it requires more than a showing that a facility
is unlikely to contribute to cascading thermal outages and introduces
more rigorous requirements than those in the TPL Reliability Standards.
Specifically, APPA, Duke, Exelon, and TAPS argue that interruption of
firm transmission service and violation of facility ratings do not
belong as elements of the test because: (1) They do not result in
instability, uncontrolled separation, or cascading failures, and are
absent from the definition of ``Reliable Operation'' in section 215 of
the FPA; \52\ (2) avoiding an interruption of firm transmission service
is a business issue; (3) a requirement specifying that the loss of a
138 kV line cannot result in interruption of local load goes beyond the
requirements of existing Reliability Standards; (4) the loss of a 138
kV line does not show a loss of bulk electric system reliability; and
(5) ``violation of facility ratings'' is unduly vague and over-broad
because it is not restricted to bulk electric system facilities other
than the facility in question and is not focused on violation of
emergency ratings caused by an outage of the facility in question.
---------------------------------------------------------------------------
\52\ Section 215 defines ``Reliable Operation'' as ``operating
the elements of the bulk-power system within equipment and electric
system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will
not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system
elements.'' 16 U.S.C. 824o(a)(4).
---------------------------------------------------------------------------
41. Commenters also argue that NERC should develop the test for
exclusions and that there should be some mechanism for entities to
challenge criticality determinations. For example, APPA argues that the
Regional Entity should establish a process for entities to challenge
criticality determinations.
c. Comments on Proposal To Include Sub-100 kV Facilities
42. Commenters also address the Commission's proposal to direct the
ERO to adopt an ``add in'' approach to sub-100 kV facilities, with most
objecting to what they perceive as the Commission's view of the
Compliance Registry.\53\ NERC argues that the Commission
mischaracterized the nature and purpose of the Compliance Registry by
suggesting that entities on the Registry must comply with all
Reliability Standards for all of their facilities.\54\ NERC explains
that the Compliance Registry does not specify which entities must
comply with any particular Reliability Standard, but that each
individual Standard specifies the entities and the facilities that are
subject to it. TAPS and APPA assert that a facility may be ``critical''
for the purpose of inclusion on the Compliance Registry, but not
``operationally significant'' for the purpose of avoiding cascading
thermal outages. For example, TAPS states that a sub-100 kV line that
connects to a black start unit and is designated as part of a
transmission operator's restoration plan would be deemed critical for
Compliance Registry purposes, but may not be operationally significant
for purposes of thermal cascading outages.\55\
---------------------------------------------------------------------------
\53\ See e.g., NERC, EEI, TAPS, TANC, Ontario Generation,
SWTDUG, and APPA.
\54\ See also TANC and Ontario Generation.
\55\ TAPS at 16; see also APPA at 28.
---------------------------------------------------------------------------
43. Several commenters request that the Commission confirm their
understanding of what is required if the Commission adopts its
proposal. ERCOT and TAPS request confirmation that the Reliability
Standard will apply only to those sub-100 kV facilities that are
already in the Compliance Registry, and that future registration will
be subject to a case-by-case demonstration of criticality. Likewise,
SWTDUG is concerned that the Commission's proposal will require non-
registered public power entities with sub-100 kV facilities to become
Registered Entities. ERCOT also requests confirmation that the only
required revision to the Reliability Standard would be the addition of
sub-100 kV facilities to the applicability section. ISO New England
requests confirmation that the Commission does not intend to create an
enforceable obligation against Regional Entities by directing them to
undertake--solely for the purpose of compliance with PRC-023-1--a
process to determine which sub-100 kV facilities are critical to the
reliability of the bulk electric system. ISO New England asserts that
NERC has already delegated to Regional Entities the role of designating
critical sub-100 kV facilities as part of the Compliance Registry
process.\56\ ISO New England seeks clarification that the Commission's
proposal merely requires the addition of a cross-reference to previous
designations of criticality made pursuant to the Compliance Registry
process.
---------------------------------------------------------------------------
\56\ ISO New England at 3.
---------------------------------------------------------------------------
44. ITC, IRC, and IESO/Hydro One support the Commission's proposal.
These commenters argue that a proactive approach should be used to
identify any facilities critical to the reliability of the bulk
electric system.
45. NERC and EEI oppose the Commission's proposal; however, both
[[Page 16921]]
concede that it may have merit and should be studied through the
Reliability Standards development process.\57\ SWTDUG and TAPS oppose
the Commission's proposal and argue that the Final Blackout Report does
not support extending the Reliability Standard to relay settings on
sub-100 kV facilities. TAPS maintains that the Commission must give
``due weight'' to NERC's exclusion of sub-100 kV facilities.
---------------------------------------------------------------------------
\57\ NERC Comments at 18-19; EEI at 17-18.
---------------------------------------------------------------------------
46. EPSA argues that the Commission's proposal lacks technical
support and fails to identify a specific reliability gap. EPSA contends
that the Commission should use ``Reliability Engineering'' to determine
if its project has a technical basis. EEI argues that few sub-100 kV
facilities are critical to the reliability of the bulk electric system.
EEI states that because it usually requires multiple 69 kV lines to
replace one 138 kV line, it is highly unlikely that sub-100 kV
facilities will cause a major cascade. EEI asserts that it is much more
likely that sub-100 kV facilities will trip to end a cascade, as
occurred during the August 2003 blackout.
3. Commission Determination
47. As discussed more fully below, we decline to direct the ERO to
adopt the ``rule out'' approach for 100 kV-200 kV facilities. However,
we adopt the NOPR proposal and direct the ERO to modify PRC-023-1 to
apply an ``add in'' approach to certain sub-100 kV facilities that
Regional Entities have already identified or will identify in the
future as critical facilities for the purposes the Compliance
Registry.\58\ Finally, we direct the ERO to modify Requirement R3 of
the Reliability Standard to include the test that planning coordinators
must use to identify sub-200 kV facilities that are critical to the
reliability of the bulk electric system.
---------------------------------------------------------------------------
\58\ Examples of such facilities include black start generation
and the ``cranking path'' from the generators to the bulk electric
system.
---------------------------------------------------------------------------
a. ``Rule Out'' Approach
48. We will not direct the ERO to adopt the ``rule out'' approach.
After further consideration, we conclude that our concerns about the
``add in'' approach can be addressed by directing the ERO to modify
Requirement R3 of the Reliability Standard to specify a comprehensive
and rigorous test that all planning coordinators must use to identify
all critical facilities.
49. In the NOPR, the Commission explained that PRC-023-1 must apply
to relay settings on all critical facilities between 100 kV and 200 kV
for it to achieve its intended reliability objective. The Commission
also stated that planning coordinators must use a process to carry out
Requirement R3 that is consistent across regions and robust enough to
identify all facilities that should be subject to the Reliability
Standard. The Commission expressed concern, however, that NERC's ``add
in'' approach could effectively exempt from the Reliability Standard's
Requirements a large percentage of facilities that should otherwise be
subject to the Standard. Since NERC did not propose any test for the
Commission to consider, the Commission proposed the ``rule out''
approach to ensure that planning coordinators identify all critical
facilities between 100 kV and 200 kV.
50. After reflecting on the rationale behind the ``rule out''
approach--namely, the goal of ensuring that planning coordinators
identify all critical facilities between 100 kV and 200 kV--and
considering the comments, we conclude that, from a reliability
standpoint, it should not matter whether PRC-023-1 employs an ``add
in'' approach or a ``rule out'' approach because both approaches should
ultimately result in the same list of critical facilities. In other
words, given a uniform and robust test, the facilities that would be
``added in'' under an ``add in'' approach should be the same as the
facilities that would remain subject to the Reliability Standard after
non-critical facilities are ruled out under the ``rule out'' approach.
Instead of concerning ourselves with the merits of an ``add in'' or
``rule out'' approach, the Commission will focus on the test
methodology that a planning coordinator uses to either ``add in'' or
``rule out'' a facility. If that test is lacking, PRC-023-1's
reliability objective will not be achieved regardless of whether an
``add in'' approach or a ``rule out'' approach is adopted.
Consequently, we decline to adopt the NOPR proposal and will not
require the ERO to adopt the ``rule out'' approach. Instead, as
discussed below, we direct the ERO to modify Requirement R3 of the
Reliability Standard to specify the test that planning coordinators
must use to identify all critical facilities.
51. In light of our decision, we do not need to address commenters'
objections to the ``rule out'' approach or speculation about the number
of 100 kV-200 kV facilities that are critical to the reliability of the
Bulk-Power System. Nevertheless, we do not accept the claim that if
PRC-023-1 had been in effect at the time of the August 2003 blackout,
it would have prevented the 345 kV lines from tripping and therefore
prevented the 100 kV-200 kV lines from tripping. We also disagree with
commenters' claim that the majority of facilities between 100 kV and
200 kV are unlikely to contribute to cascading outages at higher
voltages.
52. We disagree with commenters' assertion that if PRC-023-1 had
been in effect at the time of the August 2003 blackout, it would have
prevented the 345 kV lines from tripping and therefore prevented the
100 kV-200 kV lines from tripping. On the day of the blackout, the
Harding-Chamberlin, Hanna-Juniper, and Star-South Canton 345 kV lines
all tripped in a span of less than 45 minutes. Each of these lines
tripped and locked out because of contact with an overgrown tree.\59\
As each line failed, its outage increased the load on the remaining 138
kV and 345 kV lines, including the 345 kV Sammis-Star line,\60\ and
shifted power flows to other transmission paths. Starting at 15:39 EDT,
the first of an eventual sixteen 138 kV lines began to fail. The
tripping of these 138 kV lines occurred because the loss of the
combination of the Hardin-Chamberlin, Hanna-Juniper, and Star-South
Canton 345 kV lines overloaded the 138 kV system with electricity
flowing toward the Akron and Cleveland loads.\61\ In other words, the
cascade of 138 kV lines was precipitated by faults caused by tree
contact, not protective relays, and would not have been prevented if
PRC-023-1 had been in effect before the blackout.
---------------------------------------------------------------------------
\59\ Final Blackout Report at 57-61; 63-64.
\60\ Id. at 70.
\61\ Id. at 69-70.
---------------------------------------------------------------------------
53. As the 138 kV lines opened, they blacked out customers in Akron
and in the area west and south of Akron, ultimately dropping about 600
MW of load.\62\ Even this load shedding was not enough to offset the
cumulative effect of the 138 kV line outages on the increased loadings
of the 345 kV Sammis-Star line. The Sammis-Star line tripped at
16:05:57 EDT and triggered a cascade of interruptions on the high
voltage system, causing electrical fluctuations and facility trips such
that within seven minutes the blackout rippled from the Cleveland-Akron
area across much of the northeast United States.\63\
---------------------------------------------------------------------------
\62\ Id. at 68.
\63\ Id. at 74.
---------------------------------------------------------------------------
54. Unlike the Hardin-Chamberlin, Hanna-Juniper, and Star-South
Canton lines, which tripped because of tree contact, the Sammis-Star
line tripped due to protective zone 3 relay action that measured low
apparent impedance (depressed voltage divided by
[[Page 16922]]
abnormally high line current).\64\ There was no fault and no major
power swing at the time of the trip; rather, high flows above the
line's emergency rating together with depressed voltage caused the
overload to appear to the protective relays as a remote fault on the
system.\65\ In effect, the relay could no longer differentiate between
a remote three-phase fault and an exceptionally high loading condition.
The relay operated as it was designed to do.\66\
---------------------------------------------------------------------------
\64\ Id. at 77-78. See Figure 6.4.
\65\ Id. at 77.
\66\ Id.
---------------------------------------------------------------------------
55. To the extent that commenters' argument is that PRC-023-1 would
have prevented the loss of the Sammis-Star line, and therefore the
subsequent spread of the blackout, we do not think that it is possible
to definitively reach these conclusions on the present record.
56. Requirement R1 of PRC-023-1 directs entities to evaluate relay
loadability at 0.85 per unit voltage and a power factor angle of 30
degrees. Figure 6.4 of the Final Blackout Report indicates that the
power factor angle recorded at the time the Sammis-Star line tripped
was about 27 degrees. Although the system was in a marginally stable
operating stage, it would not require major changes to effect a further
change on the loading or further increasing the power factor angle on
this line to beyond 30 degrees. In other words, purely from the power
factor angle viewpoint, the Sammis-Star line trip may still have
occurred even if the relay loadability evaluation requirement of 30
degrees was met. In fact, in a white paper explaining the engineering
assumptions and rationales behind the Requirements in PRC-023-1, the
NERC System Protection and Control Task Force specifically stated that:
[T]he most important point to understand [about the relay
loadability evaluation requirement in Requirement R1] is that the
loadability recommendations are not absolute system conditions. They
represent a typical system operation point during an extreme system
condition. The voltage at the relay may be below the 0.85 per unit
voltage and the power factor angle may be greater than 30 degrees.
It is up to the relay settings engineer to provide the necessary
margin as is done in all relay settings.\67\
\67\ NERC Planning Committee, System Protection and Control Task
Force, ``Increase Line Loadability by Enabling Load Encroachment
Functions of Digital Relays,'' December 7, 2005 at A-1.
We agree with the NERC System Protection and Control Task Force, and
caution that setting relays pursuant to PRC-023-1 simply based on a
static and typical system operation point, without validating the relay
settings based on system conditions that the relays could experience,
and without acceptable margins applied to the minimum voltages and
power factor angles, may not achieve the reliability goals intended by
PRC-023-1.
57. Consequently, we believe that it is not possible to conclude
whether the Sammis-Star line would have tripped on loadability if PRC-
023-1 had been in effect without first setting its zone 3 relay
pursuant to PRC-023-1 and then validating the setting against the
voltages, currents, and power factor angles that were recorded during
the August 2003 Blackout. In fact, it is our view that a similar
process should be followed for the 345 kV lines in Michigan that
tripped following the loss of Sammis-Star line to determine whether
PRC-023-1 would have prevented the blackout.
58. We also disagree with commenters' assertion that that majority
of facilities between 100 kV and 200 kV are unlikely to contribute to
cascading outages at higher voltages. Prior to the dynamic cascading
stage that began with the loss of the 345 kV Sammis-Star line, when the
system was still in a marginally stable operating state (albeit not
within IROLs, as shown in Figure 5.12 in the Final Blackout Report), it
was the loss of several 138 kV facilities that contributed to the
subsequent increased loading on the 345 kV Sammis-Star line and
resulted in its tripping.\68\ A more recent example of a cascade
initiating at the 138 kV voltage level and spreading to higher voltages
is the Florida Power and Light 2008 blackout event. This event started
at the 138 kV level and cascaded into additional 138 kV, 230 kV, and
500 kV facilities. Because the operation of the protective relay is
dependent on the apparent impedance, i.e. voltage and current
quantities as measured by the relay irrespective of voltage class,
application of PRC-023-1 at only the higher voltage would not have
prevented these events. We believe that only a valid assessment with an
acceptable set of test criteria could determine whether 100 kV-200 kV
facilities are critical facilities, and therefore whether they need to
be set pursuant to PRC-023-1 to prevent such undesirable system
performance.
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\68\ Final Blackout Report at 64.
---------------------------------------------------------------------------
59. Finally we agree with APPA that cascading outages at higher
voltages are unlikely to be arrested by relay action at lower voltages.
Reliability Standard PRC-023-1 is for preventing inadvertent tripping
of Bulk-Power System facilities which could then initiate cascading
outages at any voltage level, and not for arresting cascading outages.
b. ``Add in'' Approach to Sub-100 kV Facilities
60. With respect to sub-100 kV facilities, we adopt the NOPR
proposal and direct the ERO to modify PRC-023-1 to apply an ``add in''
approach to sub-100 kV facilities that are owned or operated by
currently-Registered Entities or entities that become Registered
Entities in the future, and are associated with a facility that is
included on a critical facilities list defined by the Regional
Entity.\69\ We also direct that additions to the Regional Entities'
critical facility list be tested for their applicability to PRC-023-1
and made subject to the Reliability Standard as appropriate.
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\69\ As mentioned above, section III.d.2 of the Statement of
Compliance Registry Criteria defines ``transmission owner/operator''
as: ``[a]n 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.''
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61. Most of the comments opposing the Commission's proposal
regarding sub-100 kV facilities relate to what commenters perceive to
be the Commission's view of the relationship between individual
Reliability Standards and the Compliance Registry. For example, NERC
argues that the Commission mischaracterized the nature and purpose of
the Compliance Registry by suggesting that entities on the Registry
must comply with all Reliability Standards for all of their facilities
without regard to the applicability provisions of individual Standards.
We did not intend to create this impression. We agree with NERC that
the Compliance Registry does not specify which entities must comply
with any particular Reliability Standard. Rather, the applicability
provision of each individual Standard specifies the categories of
entities, i.e., functions, and at times the categories of facilities
that are subject to it.
62. We also agree with TAPS and APPA that it is possible, at least
in theory, that a sub-100 kV facility that has been identified by a
Regional Entity as critical for the purposes of the Compliance Registry
might not be ``critical'' with respect to PRC-023-1. Thus, we clarify
that we do not require the modified Reliability Standard to apply to
all sub-100 kV facilities that have been identified by Regional
Entities as critical facilities, but only to those that have been
identified by Regional Entities as critical facilities and are also
identified by planning coordinators, pursuant to the test
[[Page 16923]]
directed to be developed herein, as critical to the reliability of the
Bulk-Power System. In other words, the modification that we direct in
this Final Rule extends the scope of the Reliability Standard to
include any sub-100 kV facility that is: (1) Owned or operated by a
currently-Registered Entity or an entity that becomes a Registered
Entity in the future; (2) associated with a facility that is included
on a critical facilities list defined by the Regional Entity; (3)
employing load-responsive phase protection relays in its protection
system(s); and (4) identified by the test directed to be developed
herein.\70\
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\70\ Consistent with Order No. 716, we expect that sub-100 kV
facilities that are needed to supply the auxiliary power system of a
Nuclear Power plant will be included in both determinations. See
Mandatory Reliability Standard for Nuclear Plant Interface
Coordination, Order No. 716, 125 FERC ] 61,065 (2008), at P 51-53,
order on reh'g, Order No. 716-A, 126 FERC ] 61,122 (2009).
---------------------------------------------------------------------------
63. Along these same lines, ERCOT, SWTDUG, and TAPS are concerned
that the Commission's proposal will require non-registered public power
entities with sub-100 kV facilities to become Registered Entities. As
we have said, our directive applies only to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that
become Registered Entities in the future, and are associated with a
facility that is included on a critical facilities list defined by the
Regional Entity; it is not intended to supplant the process that
Regional Entities use to determine if a sub-100 kV facility should be
identified as a critical facility or if an entity should be a
Registered Entity. Similarly, our purpose is not to extend the
definition or the scope of the bulk electric system sub rosa; it is to
ensure that PRC-023-1 applies to all critical facilities as identified
in the applicability section so that the Reliability Standard can
achieve its reliability objective. Consequently, we do not intend to
require any non-Registered Entity to register on account of PRC-023-1.
Nevertheless, there might be sub-100 kV facilities that are owned or
operated by non-Registered Entities that are identified by planning
coordinators, pursuant to the test directed to be developed herein, as
critical facilities. While we do not require that these entities become
Registered Entities solely due to PRC-023-1, if a planning coordinator
applying the test directed to be developed herein identifies a sub-100
kV facility that belongs to a non-Registered Entity as a critical
facility, we expect that the planning coordinator will inform the
Regional Entity and that the Regional Entity will consider this
information in light of its existing registration guidelines and
procedures.\71\ Similarly, we expect that Regional Entities will
consider this information when determining whether a sub-100 kV
facility should be included in a regional definition of the bulk
electric system.\72\
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\71\ In general, we expect that the results of the planning
coordinator analysis and the processes used by the Regional Entities
to identify critical facilities would have similar outcomes.
\72\ We note that the definition of the bulk electric system is
subject to change. See Order No. 693, FERC Stats. & Regs. ] 31,242
at P 77.
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64. With respect to ISO New England's request for confirmation that
the Commission does not intend to create an enforceable obligation
against Regional Entities by directing them to undertake--solely for
the purpose of compliance with PRC-023-1--a process to determine which
sub-100 kV facilities are critical to the reliability of the Bulk-Power
System, it should be clear from what we have already said that we do
not intend to create such an obligation. As we have explained, our
directive requires planning coordinators, not Regional Entities, to
determine which sub-100 kV facilities should be subject to the
Reliability Standard. Moreover, we agree with ISO New England's
assertion that Regional Entities have already been delegated by NERC
the role of designating critical sub-100 kV facilities as part of the
Compliance Registry process.\73\
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\73\ ISO New England at 3. See also Order No. 693, FERC Stats. &
Regs. ] 31,242, at P 101.
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65. Some commenters question the technical basis for extending PRC-
023-1 to sub-100 kV facilities. For example, EEI argues that because it
usually requires multiple 69 kV lines to replace one 138 kV line, it is
highly unlikely that sub-100 kV facilities will cause a major cascade
and much more likely that sub-100 kV facilities will trip to end a
cascade, as occurred during the August 2003 blackout. EPSA argues that
the Commission should apply ``Reliability Engineering'' to determine
whether there is a technical basis for its proposal. SWTDUG and TAPS
argue that the Final Blackout Report does not support extending the
Reliability Standard to relay settings on sub-100 kV facilities.
66. We will not follow EPSA's suggestion to use Reliability
Engineering to identify critical facilities. In our view, it is more
appropriate to identify critical sub-100 kV facilities (and, for that
matter, critical 100 kV-200 kV facilities) by using established
criteria specific to the electric industry.\74\ The TPL Reliability
Standards establish desired system performance requirements specific to
a set of contingencies under a set of base cases that cover critical
system conditions of the Bulk-Power System, while Reliability
Engineering, as described by EPSA, is primarily used in reliability-
centered maintenance to assess the optimum intervals and practices for
facility maintenance. We strongly believe that, for the purposes of
PRC-023-1, it is appropriate to use requirements that are specific to
the electric industry and that are supported by decades of foundational
planning and operating principles and experiences and that are embedded
in the TPL Reliability Standards rather than criteria that may be more
appropriate to maintenance practices.
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\74\ EPSA states that ``Reliability Engineering'' is currently
used to develop modeling and maintenance strategies for complex
systems, including multiple failure testing, which has been applied
to systems such as oil pipelines and civil infrastructures. EPSA at
6.
---------------------------------------------------------------------------
67. We also reject EEI's claim that there is no technical basis for
extending PRC-023-1 to sub-100 kV facilities. Relay settings on such
facilities should be subject to PRC-023-1 because their loss can also
affect the reliability of the Bulk-Power System. We also reject TAPS's
assertion that the Commission must exclude sub-100 kV facilities since
the Commission is required under section 215(d)(2) of the FPA to give
``due weight'' to the technical expertise of the ERO. NERC has not
provided a sufficient technical justification to support the exclusion
of sub-100 kV facilities. In its comments, NERC states that extending
PRC-023-1 to sub-100 kV facilities ``may have merit'' and ``would
require further study,'' \75\ indicating that it did not affirmatively
consider subjecting certain sub-100 kV facilities to the Reliability
Standard and then reject the idea on the basis of its technical
expertise. Moreover, NERC has not offered a technical basis for
opposing the Commission's proposal. NERC's comments on the Commission's
proposal pertain exclusively to the relationship between the Compliance
Registry and entities' obligations to comply with Reliability
Standards. Contrary to TAPS's assertion, NERC does not offer a
technical argument against including certain sub-100 kV facilities in
PRC-023-1.
---------------------------------------------------------------------------
\75\ NERC Comments at 18.
---------------------------------------------------------------------------
68. Similarly, with respect to EEI's and NERC's claim that any
expansion of the Reliability Standard must be developed through the
Reliability Standards development process, we clarify that, as with our
other directives in this Final Rule, we do not prescribe this specific
change as an exclusive
[[Page 16924]]
solution to our reliability concerns regarding sub-100 kV facilities.
As we have stated, the ERO can propose an alternative solution that it
believes is an equally effective and efficient approach to addressing
the Commission's reliability concerns about the absence of sub-100 kV
facilities from PRC-023-1. Moreover, while we expect planning
coordinators to use the same test to identify critical sub-100 kV
facilities as they use to identify critical 100 kV-200 kV facilities,
the ERO is free, pursuant to Order No. 693, to propose a modified
Reliability Standard that contains a different test for sub-100 kV
facilities, provided that the test represents an ``equivalent
alternative approach.''
c. Test for Identifying Sub-200 kV Facilities
i. Overview
69. Finally, pursuant to section 215(d)(5) of the FPA, we direct
the ERO to modify Requirement R3 of the Reliability Standard to specify
the test that planning coordinators must use to determine whether a
sub-200 kV facility is critical to the reliability of the Bulk-Power
System. We direct the ERO to file its test, and the results of applying
the test to a representative sample of utilities from each of the three
Interconnections, for Commission approval no later than one year from
the date of this Final Rule.\76\
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\76\ We expect that the representative samples will include
large and small, rural and metropolitan entities reflecting various
topologies.
---------------------------------------------------------------------------
70. As we explained above, the Commission proposed to direct the
ERO to adopt the ``rule out'' approach for 100 kV-200 kV facilities
because it was concerned that NERC's ``add in'' approach would
effectively exempt a large percentage of facilities that should
otherwise be subject to the Reliability Standard. Contrary to the
suggestion of some commenters, the Commission's concern was not based
on a latent distrust of planning coordinators, but on the absence of a
mandatory test in the Reliability Standard for planning coordinators to
use to identify critical facilities.\77\ Without such a test, the
Commission has no way of determining whether the ``add in'' approach
will result in a comprehensive list of critical facilities. As we also
explained above, because the ``rule out'' approach and the ``add in''
approach should ultimately result in the same list of critical
facilities, the choice between them is less important, from a
reliability standpoint, than the test that planning coordinators must
use to determine whether a facility is a critical facility. We
conclude, therefore, that the lack of such a mandatory test is a matter
that must be addressed by the ERO to ensure that the Reliability
Standard meets its reliability objective. Otherwise, there is no
guarantee that all planning coordinators will use comprehensive and
rigorous criteria that is consistent across regions to identify all
critical sub-200 kV facilities, leaving the Bulk-Power System
vulnerable to similar problems that resulted in the cascade during the
August 2003 blackout.
---------------------------------------------------------------------------
\77\ NERC agrees that there must be consistent criteria for
determining which 100 kV-200 kV facilities are critical facilities.
Id. at 12.
---------------------------------------------------------------------------
71. Consistent with Order No. 693, we provide ``sufficient guidance
so that the ERO has an understanding of the Commission's concerns and
an appropriate, but not necessarily exclusive, outcome to address those
concerns.'' \78\ In this way, we ensure that the Commission's directive
is not ``so vague that the ERO would not know how to adequately
respond.'' \79\ Thus, below we provide guidance for the development of
a test to determine critical facilities.\80\
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\78\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 185.
\79\ Id.
\80\ While the ERO is free to submit a modified Reliability
Standard that adopts the guidance set forth below as the mandatory
test, we will also consider ``an equivalent alternative approach
provided that the ERO demonstrates that the alternative will
adequately address the Commission's underlying concern or goal as
efficiently and effectively as the Commission's proposal'' and is
consistent with our guidance. Id. P 186.
---------------------------------------------------------------------------
72. We first observe that PRC-023-1 directs planning coordinators
to identify facilities that are ``critical to the reliability of the
bulk electric system.'' In contrast, Recommendation 21A of the Final
Blackout Report refers to ``operationally significant'' facilities.
APPA, Exelon, and TAPS argue that, in the context of the Reliability
Standard, ``critical to the reliability of the bulk electric system''
and ``operationally significant'' carry the same meaning and describe
the same facilities. Exelon adds that drafting history confirms that
the Reliability Standard drafting team intended this interpretation.
73. We agree. In our view, ``critical to the reliability of the
bulk electric system'' in PRC-023-1 and ``operationally significant''
in Recommendation 21A are intended to have the same meaning because
PRC-023-1 was developed to implement Recommendation 21A. This
conclusion sheds some light on what facilities should be identified as
``critical to the reliability of the bulk electric system'' because, in
Recommendation 21A, the Task Force listed lines that are part of
monitored flowgates and interfaces as examples of ``operationally
significant'' facilities. Importantly, the Task Force did not recommend
that NERC limit its extended review only to monitored flowgates and
interfaces; it merely cited monitored flowgates and interfaces as
examples of ``operationally significant'' facilities. If a facility
trips on relay loadability following an initiating event and
contributes to undesirable system performance similar to what occurred
during the August 2003 blackout (e.g., cascading outages and loss of
load) in the same way that the loss of monitored flowgates and
interfaces contributed to the August 2003 blackout, the facility is
operationally significant for the purposes of Recommendation 21A, and
therefore critical to the reliability of the bulk electric system for
the purposes of PRC-023-1. For example, the 138 kV lines shown in
Figure 5.12 of the Final Blackout Report were not part of the monitored
flowgate of the 345 kV Sammis-Star line or any other flowgate in
FirstEnergy, but the loss of these 138 kV facilities affected loading
on Sammis-Star, and the loss of Sammis-Star was the point at which the
blackout went into its dynamic cascading phase. Thus, we reject
assertions, made in the context of comments on the ``rule out''
approach, that facilities that are not part of a defined and routinely
monitored flowgate should automatically be excluded from the
Reliability Standard's scope.
ii. Guidance on the Test
74. Neither the Final Blackout Report nor the Reliability Standard
establishes a mandatory test for planning coordinators to use to
determine if a facility is ``operationally significant'' or ``critical
to the reliability of the bulk electric system'' with respect to relay
settings and the prevention of cascading outages. However, in its
comments on the NOPR, NERC includes the guidance for identifying
operationally significant 100 kV-200 kV facilities that the NERC System
Protection and Control Task Force supplied to Regional Entities during
the voluntary Beyond Zone 3 relay review and mitigation program. This
guidance advised Regional Entities to identify:
All circuits that are elements of flowgates in the Eastern
Interconnection, Commercially Significant Constraints in the Texas
Interconnection, or Rated Paths in the Western Interconnection. This
includes both the monitored and outage element for OTDF sets.
All circuits that are elements of system operating limits (SOLs)
and interconnection reliability operating limits (IROLs), including
both monitored and outage elements.
[[Page 16925]]
All circuits that are directly related to off-site power supply
to nuclear plants. Any circuit whose outage causes unacceptable
voltages on the off-site power bus at a nuclear plant must be
included, regardless of its proximity to the plant.
All circuits of the first 5 limiting elements (monitored and
outaged elements) for transfer interfaces determined by regional and
interregional transmission reliability studies. If fewer than 5
limiting elements are found before reaching studied transfers, all
should be listed.
Other circuits determined and agreed to by the reliability
authority/coordinator and the Regional Reliability Organizations.
75. After careful review, we conclude that the guidance provided by
the NERC System Protection and Control Task Force, if applied
appropriately, would identify some, but likely not all, critical sub-
200 kV facilities. There are some critical facilities that the guidance
would not identify and would need to identify in order for it to be a
fully acceptable test and meet the reliability objectives of PRC-023-1.
76. In the Commission's view, the NERC System Protection and
Control Task Force guidance focuses primarily on identifying facilities
that are ``operationally significant'' between regions (e.g., between
ECAR and SERC) or between sub-regions (e.g., between Southern and
Entergy) and would not necessarily identify operationally significant
facilities within a sub-region or a company.\81\ In order to achieve
its objective, however, PRC-023-1 must apply to relay settings on all
operationally significant sub-200 kV facilities that could trip on
relay loadability and contribute to cascading outages and the loss of
load, including those within a sub-region or a company. The ERO could
refine the NERC System Protection and Control Task Force's guidance
into an acceptable mandatory test by, among other things, revising it
to include the assessment and identification of facilities within a
region, sub-region, or company, whose inadvertent outage due to relay
loadability could result in undesirable system performance.\82\
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\81\ We understand that some interregional studies include only
a portion of all the lines with the remaining modeled as
equivalents. Such an analysis could not possibly address the
operational significance of the lines that were modeled only as
equivalents.
\82\ The ERO is not limited to proposing a revised version of
the NERC System Protection and Control Task Force's guidance as the
mandatory test. It can also develop a new test to identify critical
sub-200 kV facilities or refine other aspects of the System
Protection and Control Task Force test. Any test that the ERO
submits, including one based on the NERC System Protection and
Control Task Force's guidance, must be consistent with the general
guidelines set forth in this Final Rule.
---------------------------------------------------------------------------
77. The test for identifying operationally significant/critical
sub-200 kV facilities should identify facilities that must have their
relays set in accordance with PRC-023-1 to avoid the undesirable system
performance that Recommendation 21A was intended to prevent. It should
also describe the steady state and dynamic base cases that planning
coordinators must use in their assessment.
78. Recommendation 21A of the Final Blackout Report was developed
to prevent undesirable system performance like the undesirable
performance that occurred during the August 2003 blackout. During the
blackout, the inadvertent tripping of facilities due to loadability
resulted in undesirable system performance in the form of cascading
outages and the loss of load. Since PRC-023-1 implements Final Blackout
Recommendation No. 21A, it too must prevent the undesirable system
performance that would include, among other performance factors,
cascading outages and the loss of load.
79. To achieve this goal, the test to determine which sub-200 kV
facilities are subject to PRC-023-1 must include or be consistent with
the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all
Category of Contingencies used in transmission planning. As discussed
in the NOPR, the Commission expects that the base cases used to
determine the facilities subject to PRC-023-1 will include various
generation dispatches, topologies, and maintenance outages assumed in
the planning time frame, and will consider the effect of redundant and
backup protection systems.\83\ As such, the base cases shall bracket
all stable operating conditions.
---------------------------------------------------------------------------
\83\ NOPR, FERC Stats. & Regs. ] 32,642 at P 43, n.71. A ``base
case'' refers to the transmission system model used for performing
planning studies.
---------------------------------------------------------------------------
80. Thus, the ERO must develop a test that: (a) Defines
expectations of desirable system performance; and (b) describes the
steady state and dynamic base cases that the planning coordinator must
use in its assessments to carry out Requirement R3. The goal of the
test must be consistent with the general reliability principles
embedded in the existing series of TPL, Transmission Operations (TOP),
Reliability Coordination (IRO), and Protection and Control (PRC)
Reliability Standards. This is, in fact, good utility practice
worldwide in that, if an initiating event \84\ results in inadvertent
outage \85\ or the tripping of other non-faulted facilities that would
result in cascading outages or loss of load, or violation of any of the
applicable criteria, these facilities must be identified for remedial
actions (such as equipment modifications, or a reduction in IROLs or
SOLs) to ensure Reliable Operation. We provide guidance on both
features of the test below.
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\84\ In power systems, an ``initiating event'' generally refers
to any event on the electric system that begins a series of actions.
For transmission planning purposes, an initiating event is usually
modeled as a type of fault. 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.'' See NERC Glossary of Terms
used in Reliability Standards at 7.
\85\ An ``inadvertent outage'' generally refers to an unplanned
outage of a facility. For the purposes of PRC-023-1, an inadvertent
outage is the tripping of a facility due to loadability conditions.
---------------------------------------------------------------------------
iii. Desirable System Performance
81. During the August 2003 blackout, facilities (regardless of the
voltage class and whether or not they were part of monitored flowgates)
inadvertently tripped due to loadability conditions, resulting in
undesirable system performance under the TPL Reliability Standards in
the form of exceeding SOL and IROL limits, cascading outages, and the
loss of load. Consequently, consistent with the TPL Reliability
Standards, the first component of desirable system performance that the
test must seek to maintain is the continuity of all firm load supply
except for supply directly served by the faulted facility. In other
words, it is the Commission's view that the test must identify
facilities necessary to achieve the reliability performance for
Category B and Category C contingencies--which would include no non-
consequential load loss (for Category B) and no cascading outages (for
Category B and Category C) for all stable operating conditions.\86\
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\86\ In Order No. 693, the Commission explained that the term
``consequential load loss'' refers to ``load that is directly served
by the elements that are removed from service as a result of the
contingency.'' Order No. 693, FERC Stats. & Regs. ] 31,242 at P
1794, n.461.
---------------------------------------------------------------------------
82. The TPL Reliability Standards address, among other things, the
type of simulations and assessments that must be performed to ensure
that reliable systems are developed to meet present and future systems
needs.\87\ Table 1 of the TPL Reliability Standards establishes the
desired system performance requirements for a range of contingencies
grouped according to the number of elements forced out of service as a
result of the contingency.
[[Page 16926]]
Consistent with Table 1 of the TPL Reliability Standards, with the
exception of extreme contingency events, the system should always be
stable and within both thermal and voltage limits for Reliable
Operation.\88\ This is the second component of desirable system
performance that the test must seek to determine.
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\87\ Id. at P 1683.
\88\ Extreme contingency events are the loss of two or more
(multiple) elements (Category D).
---------------------------------------------------------------------------
83. Finally, while the curtailment of firm transfers is permitted
to prepare for the next contingency, it is generally not the desired
system performance for single contingencies required by Table 1 of the
TPL Reliability Standards. Thus, continuity of all firm transfers is
the third component of desirable system performance.\89\
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\89\ See Reliability Standard TPL-002-0. Footnote b of Table 1
allows for the interruption of firm load for consequential load
loss. This footnote is currently the subject of an order setting a
deadline for required revisions in RM06-16-009.
---------------------------------------------------------------------------
84. In sum, because the Bulk-Power System is planned and operated
as a minimum criterion to maintain Reliable Operation for the single
contingency loss of any transmission facility,\90\ for Category B
contingencies, desirable system performance includes: (1) Continuity of
all firm load supply except for supply directly served by the faulted
facility and no cascading outages; (2) the maintenance of all
facilities within their applicable thermal, voltage, or stability
ratings (short time ratings are applicable); and (3) the continuance of
all firm transfers.\91\ For Category C contingencies, desirable system
performance includes: (1) Continuity of all firm load supply except for
planned interruptions and no cascading outages; (2) the maintenance of
all facilities within their applicable thermal, voltage, or stability
ratings (short time ratings are applicable); and (3) the continuance of
all firm transfers that are not part of planned interruptions.\92\
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\90\ Reliability Standard TOP-002-0, Normal Operations Planning,
Requirement R6 establishes that each balancing authority and
transmission operator shall plan to meet unscheduled changes in syst
em configuration and generation dispatch (at a minimum N-1
Contingency Planning) in accordance with NERC, Regional Reliability
Organization, sub-regional, and local reliability requirements.
\91\ See Reliability Standard TPL-002-0. Footnote b of Table 1
allows for the interruption of firm load for consequential load
loss.
\92\ See Reliability Standard TPL-003-0. Footnote c of Table 1
allows for the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of
certain generators, and/or the curtailment of contracted Firm (non-
recallable reserved) electric power transfers necessary to maintain
the overall reliability of the interconnected transmission systems.
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iv. Steady State and Dynamic Base Cases
85. With respect to the steady state and dynamic base cases that
planning coordinators must use as part of their assessments, the
Commission stated in the NOPR that it expects planning coordinators to
use base cases that include various generation dispatches, topologies,
and maintenance outages, and that consider the effect of redundant and
backup protection systems. The Commission also stated that the process
for identifying critical facilities must include the same system
simulations and assessments as the TPL Reliability Standards for all
stable operating conditions. The TPL Reliability Standards establish
the types of simulations and assessments that must be performed to
ensure that reliable systems are developed to meet present and future
system needs. It is through these simulations and assessments that the
planning authority and transmission planner demonstrate that their
portion of the interconnected transmission system is planned for
Reliable Operation under contingency conditions. In order to produce a
``valid'' assessment, the planning authority or transmission planner
must demonstrate that its network can be operated to supply projected
customer demands and projected firm transmission service, at all demand
levels, over the range of forecast system demands, and under the
contingency conditions defined in Table 1.\93\ The Commission
understands that Category B contingencies would cover most of the
primary relay applications and Category C contingencies would cover
most of the backup and remote circuit breaker failure relay
applications. However, if a portion of a system is expected to be
operated differently than the minimal TPL base cases, additional base
cases should be included to include all stable operating conditions.
---------------------------------------------------------------------------
\93\ In order for a planning authority and transmission provider
to produce a ``valid'' assessment, the assessment must be
demonstrated as satisfying each of the criteria established in TPL-
002-0 through TPL-004-0, Requirement R1.
---------------------------------------------------------------------------
86. In addition to the TPL Reliability Standards, the TOP
Reliability Standards are relevant to the steady state and dynamic base
cases that reliability entities must use as part of their assessments.
The TOP Reliability Standards establish, among other things, the
responsibilities and decision-making authority for Reliable Operation
in real-time. Reliability Standard TOP-002-0 establishes requirements
for operation plans and procedures essential for Reliable Operation,
including development of SOLs and IROLs that will result in acceptable
system responses for unplanned events.
87. At a minimum, the Bulk-Power System is planned and operated to
maintain Reliable Operation for the single contingency loss of any
transmission facility.\94\ Consequently, the base cases that planning
coordinators must use in their assessments for PRC-023-1 applicability
should represent, at a minimum, the fundamental base case categories to
plan for Reliable Operation and the real-time response for Reliable
Operation. Fundamental base case categories may be more extensive than
those that are central to meeting the performance requirements
established in TPL-002-0, Requirement R1 if they do not include all
reliable operating conditions. We believe that initiating events that
represent all feasible types and locations of faults, including
evolving faults, must be simulated in each of the fundamental base case
categories to determine the performance of the system. This is
necessary for PRC-023-1 applicability because any of these initiating
events can occur and must be included in determining performance. It is
also consistent with the development of valid transmission assessments
required by the TPL Reliability Standards.\95\ Under this approach, a
facility would be identified as a critical facility if, during a
simulation starting with the base cases, its removal from service
following an initiating event would prevent desirable system
performance, as we have defined it here.
---------------------------------------------------------------------------
\94\ See Reliability Standard TPL-002-0, System Performance
Following Loss of a Single BES Element. See also Reliability
Standard TOP-002-0, Normal Operations Planning, Requirement R6 that
establishes that each balancing authority and transmission operator
shall plan to meet unscheduled changes in system configuration and
generation dispatch (at a minimum N-1 Contingency Planning) in
accordance with NERC, Regional Reliability Organization, sub-
regional, and local reliability requirements.
\95\ See Order No. 693, FERC Stats. & Regs. ] 32,642 at P 1683.
---------------------------------------------------------------------------
88. With this in mind, base case categories in the application of a
test to identify critical facilities must:
(1) Represent the full range of demand and transfer levels. This is
consistent with TPL-002-0, Requirement R1.3.5 (which requires that all
projected firm transfers be modeled) and TPL-002-1, Requirement R1.3.6
(which requires that all studies and simulations be performed and
evaluated for selected demand levels over the range of forecast system
demands);
(2) Include all stable operating conditions and allowable
topologies,
[[Page 16927]]
such as all allowable planned outages. This is consistent with TPL-002-
0, Requirement R1.3.12 (which requires that the planned (including
maintenance) outage of any bulk electric equipment (including
protection systems or their components) be included at those demand
levels for which planned (including maintenance) outages are
performed); and TOP-004 Requirement R4 (which requires operating the
actual system in a known operating state);
(3) Include the effects of the protection system design and
settings of the as designed protection systems with identification of
those that are not within the Requirements of PRC-023-1. This is
consistent with TPL-002-0, Requirement R1.3.8 with regard to existing
and planned protection systems;
(4) Include the effects of the failure of a single component within
the as designed Protection Systems, consistent with TPL-002-0
Requirement R1.3.10, but with regard to backup and redundant protection
systems; and
(5) Include various generation dispatch patterns. This is
consistent with TOP-002-0 Requirement R6 (which requires that each
balancing authority and transmission operator plan to meet unscheduled
changes in system configuration and generation dispatch (at a minimum
N-1 contingency planning) in accordance with NERC, Regional Reliability
Organization, sub-regional and local reliability requirements).
89. Our guidance above for developing a test to determine
operationally significant facilities that should be subject to PRC-023-
1 is consistent with Recommendation No. 21A of the Final Blackout
Report and with planning and operating practices for Reliable Operation
of the Bulk-Power System. Using a flowgate as an example, to derive the
IROL of a given flowgate under a given range of system conditions, the
TOP operations planner, in carrying out day-ahead reliability
assessments, would simulate contingencies on critical facilities at a
given loading on the flowgate, proceeding through the list of all
critical and operationally significant facilities that form the
monitored flowgates or other facilities as determined to be applicable,
either by actual simulation tests or engineering judgment, to eliminate
the less critical facilities that are not binding to the IROL and
facilities that are not part of that flowgate. The derived IROLs would
be valid only if none of the remaining flowgate facilities
inadvertently trip with the binding facility or facilities on which the
contingency is applied. Similarly, for the purposes of the test
described above, the facilities that are not ``operationally
significant,'' and therefore can be excluded from PRC-023-1, would be
those that trip due to loadability conditions at the same time as an
initiating event involving a critical or operationally significant
facility but do not impede desirable system performance.
90. For the particular flowgate under analysis by the TOP
operations planner, the limiting facilities are those that result in
the lowest IROL, and thus are commonly referred to as critical
facilities. All the remaining flowgate facilities and other facilities
that are not part of the flowgate under analysis are operationally
significant for two main conditions: (i) Following a contingency on a
binding or critical facility, they will not trip inadvertently and
result in an increase in the loadings on other facilities and/or stable
power swings that could result in additional trips, thereby
invalidating the derived IROL; \96\ and (ii) the outage of these
operationally significant facilities would reduce the IROL since the
flowgate would have one less element before a contingency on the
critical facility is applied. Similar analysis would be conducted for
other facilities that are not part of a flowgate.
---------------------------------------------------------------------------
\96\ In Order No. 693, the Commission explained that ``[i]n
deriving SOLs and IROLs * * * the functions, settings, and
limitations of protection systems are recognized and integrated.''
Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1435.
---------------------------------------------------------------------------
v. Response to Relevant Comments
91. The Commission received comments pertaining to its statements
about the process for identifying critical 100 kV-200 kV facilities and
its proposal to permit case-by-case exceptions for the limited number
of facilities that are not critical to the reliability of the bulk
electric system and that would not result in cascading outages,
instability, uncontrolled separation, violation of facility ratings, or
interruption of firm transmission service.\97\ While some comments are
no longer relevant given the Commission's decision not to adopt the
``rule out'' approach, others bear on how to understand the designation
``critical to the reliability of the bulk electric system'' in the
context of Requirement R3.
---------------------------------------------------------------------------
\97\ NOPR, FERC Stats. & Regs. ] 32,642 at P 43.
---------------------------------------------------------------------------
92. For example, APPA argues that the Commission should allow some
diversity in regional definitions of critical facilities to account for
physical differences in network topology, design, and performance. To
this end, APPA proposes that the Commission direct NERC to develop a
process whereby each region can develop a common region-wide approach
to identifying critical facilities.\98\ We believe that the test set
forth above is best implemented uniformly across all regions. We direct
a uniform approach rather than the one suggested by APPA because, as
NERC comments in its petition, the effects of PRC-023-1 are not
constrained to regional boundaries.\99\ Any test to identify critical
facilities must be consistent across regions so that the effects of
protective relay operation are consistent across regions.
---------------------------------------------------------------------------
\98\ APPA at 17, 26-27.
\99\ NERC Petition at 18-19, 39-41.
---------------------------------------------------------------------------
93. Duke comments that application of the existing TPL standards to
its Midwest and Carolina systems has not identified any sub-200 kV
facilities as critical (i.e., there have been no showings that the loss
of any such facilities could result in cascading outages, instability,
or uncontrolled separation).\100\ As we have explained, however, the
test that would be developed by the ERO and that would adhere to the
guidance we provide in this Final Rule would take into consideration
both the desired system performance that PRC-023-1 was developed to
achieve and the desired system performance required by the TPL
Reliability Standards for Reliable Operation.
---------------------------------------------------------------------------
\100\ Duke adds that potential revisions to the TPL Reliability
Standards appear as though they will raise the bar in clarifying the
requirements for firm transmission service (i.e., it appears that
there will be more restrictions on loss of local load that is not
connected to a faulted system element), but are unlikely to result
in many facilities under 200 kV being considered critical to bulk
electric system reliability.
---------------------------------------------------------------------------
94. We also note that some commenters argue that the Reliability
Standard should not apply to radial transmission lines and Category D
Contingencies. With regard to radial transmission lines, we note that
the NERC definition of ``bulk electric system'' does not include radial
transmission facilities serving load with only one transmission source.
We reiterate that we do not intend to expand the applicability of PRC-
023-1 beyond NERC's Statement of Registry Criteria.
95. Additionally, we do not conclude that the applicability of PRC-
023-1 should be determined based on Category D contingencies (pursuant
to Table I of the TPL Reliability Standards). We understand that relay
settings cannot be determined with great certainty for extreme multi-
contingency conditions--the types of conditions consistent with the
Category D contingencies of the TPL
[[Page 16928]]
Reliability Standards. In fact, Reliability Standard TPL-004-0 requires
that the planning authority and transmission planner demonstrate
through a valid assessment and documentation that their portion of the
interconnected electric system is evaluated only for the risks and
consequences of such events.
96. Some commenters argue that violation of facility ratings and
interruption of firm transmission service should not be part of the
applicability test. We are not persuaded by this argument because, as
previously discussed, these are included in the three reliability
components of desirable system performance.
97. Finally, commenters argue that there should be some mechanism
for entities to challenge criticality determinations. We agree that
such a mechanism is appropriate and direct the ERO to develop an
appeals process (or point to a process in its existing procedures) and
submit it to the Commission no later than one year after the date of
this Final Rule.
D. Generator Step-Up and Auxiliary Transformers
1. Omission From the Reliability Standard
98. NERC stated that generator step-up transformer relay
loadability was intentionally omitted from PRC-023-1 and would be
addressed in a future Reliability Standard.\101\
---------------------------------------------------------------------------
\101\ The Commission notes that in its comments NERC refers to
``generator relay loadability.'' In the context of our
determination, we understand ``generator step-up and auxiliary
transformer loadability'' and ``generator relay loadability'' to
refer to the same thing.
---------------------------------------------------------------------------
a. NOPR Proposal
99. In the NOPR, the Commission stated that the ERO must address
generator step-up and auxiliary transformer relay loadability in a
timely manner and proposed directing the ERO to modify PRC-023-1 to
include these issues. The Commission also requested comments suggesting
a reasonable time frame for the ERO to either modify PRC-023-1 to
address generator step-up and auxiliary transformer relay loadability
or to develop a new Reliability Standard addressing these issues.
b. Comments
100. NERC states that within two years it expects to submit to the
Commission a Reliability Standard that addresses generator relay
loadability. NERC explains that a team under the NERC System Protection
and Control Subcommittee is working with the Institute of Electrical
and Electronics Engineers (IEEE) Power System Relay Committee on a
technical reference document (Power Plant and Transmission System
Protection and Coordination) that addresses transmission protection
coordination with generation protection systems, provides technical
guidance for the revision of PRC-001,\102\ and includes technically
based loadability requirements.\103\ NERC adds that generator relay
loadability is just a single facet of the total system protection
coordination requirement between generators and transmission lines, and
recommends that all coordination issues between generators and
transmission lines, including generator step-up and auxiliary
transformer relay loadability, reside in PRC-001-2.
---------------------------------------------------------------------------
\102\ The purpose of PRC-001 is to ensure that system protection
is coordinated among operating entities.
\103\ NERC presented a draft of the technical reference document
at its September 2009 meeting.
---------------------------------------------------------------------------
101. Many commenters agree that generator step-up and auxiliary
transformer relay loadability must be addressed in a timely manner, but
in a separate Reliability Standard from PRC-023-1. In general, these
commenters argue that properly addressing generator step-up and
auxiliary transformer relay loadability requires in-depth technical
analysis and careful consideration of related protection and
coordination issues and should not be rushed to accommodate PRC-023-1.
102. Entergy argues that the NOPR appears to treat generator step-
up and auxiliary transformers as transmission-related facilities,
contrary to the Commission's ratemaking precedent. Entergy explains
that generator step-up and auxiliary transformers are not transmission
facilities, and that their function is to connect generation capacity
to the transmission grid at appropriate voltage levels. Entergy adds
that when generation is off-line, neither generator step-up
transformers nor auxiliary transformers are required for transmission
throughput.
103. The PSEG Companies argue that developing generator step-up and
auxiliary transformer loadability requirements requires a significant
effort by NERC and generation companies, and once developed, may
require generation companies to conduct specific engineering studies
for each of their generator step-up transformers. The PSEG Companies
suggest that the Commission direct NERC to consider whether it can
establish and determine a generic rating percentage.
c. Commission Determination
104. We decline to adopt the NOPR proposal and will not direct the
ERO to modify PRC-023-1 to address generator step-up and auxiliary
transformer loadability. After further consideration, we conclude that
it does not matter if generator step-up and auxiliary transformer
loadability is addressed in a separate Reliability Standard, so long as
the ERO addresses the issue in a timely manner and in a way that is
coordinated with the Requirements and expected outcomes of PRC-023-1.
105. In light of the ERO's statement that within two years it
expects to submit to the Commission a proposed Reliability Standard
addressing generator relay loadability, we direct the ERO to submit to
the Commission an updated and specific timeline explaining when it
expects to develop and submit this proposed Standard. While we
recognize that generator relay loadability is a complex issue that
presents different challenges than transmission relay loadability, we
note that more than six years have passed since the August 2003
blackout and there is still no Reliability Standard that addresses
generator relay loadability. With this in mind, the Commission will not
hesitate to direct the development of a new Reliability Standard if the
ERO fails to propose a Standard in a timely manner. While the ERO is
developing a technical reference document to facilitate the development
of a Reliability Standard for generator protection systems, only
Reliability Standards create enforceable obligations under section 215
of the FPA.
106. We also expect that the ERO will develop the Reliability
Standard addressing generator relay loadability as a new Standard, with
its own individual timeline, and not as a revision to an existing
Standard. While we agree that PRC-001-1 requires, among other things,
the coordination of generator and transmission protection systems, we
think that generator relay loadability, like transmission relay
loadability, should be addressed in its own Reliability Standard if it
is not to be addressed with transmission relay loadability.
107. Additionally, although we do not adopt the NOPR proposal, we
reject Entergy's claim that including generator and transmission relay
loadability in the same Reliability Standard would conflict with how
the Commission treats generator step-up transformers for the purposes
of ratemaking. The Commission's primary objectives in ratemaking differ
from its central objectives concerning reliability
[[Page 16929]]
regulation. In the ratemaking context, the Commission is concerned that
jurisdictional generator step-up and auxiliary transformers are
classified in a way that ensures just and reasonable rates. In the
reliability context, addressing transmission and generator relay
loadability in the same Reliability Standard facilitates the
reliability goal of ensuring coordination between transmission and
generator protection systems, as required by PRC-001-1.
108. Finally, the PSEG Companies suggest that the ERO consider
whether a generic rating percentage can be established for generator
step-up transformers and, if so, determine that percentage. Although we
do not adopt the NOPR proposal, we encourage the ERO to consider the
PSEG Companies' suggestion in developing a Reliability Standard that
addresses generator relay loadability.
2. Generator Step-Up Transformer Relays as Back-Up Protection
a. Commission's Statements in the NOPR
109. In describing PRC-023-1 in the NOPR, the Commission emphasized
that:
[T]he 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. * * *
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 [] PRC-023-
1.\104\
---------------------------------------------------------------------------
\104\ NOPR, FERC Stats. & Regs. ] 32,642 at P 33 (emphasis
added).
---------------------------------------------------------------------------
b. Comments
110. EPSA and Ontario Generation disagree with the Commission's
statements and argue that the Commission's example contains an error.
Ontario Generation asserts that protective relaying that does not
directly sense a current flow on a particular transmission circuit
cannot affect its loadability. In that respect, Ontario Generation
argues that the Reliability Standard's existing requirements correctly
refer to protection systems at specific circuit terminals.
111. EPSA and Ontario Generation also challenge the Commission's
implication that generator step-up transformer relays are subject to
the Reliability Standard if their purpose is to provide backup
protection to transmission lines. The commenters assert that because
phase fault back-up protection on the low voltage side of a generator
step-up transformer is designed to detect un-cleared faults on the
system, with the primary function of protecting the generator and the
transformer from supplying a prolonged fault current, the relays
discussed by the Commission are set pursuant to IEEE Standard C37.102
instead of PRC-023-1.
c. Commission Determination
112. We reiterate that the requirements of PRC-023-1 apply to all
protection systems as described in Attachment A that are intended to
provide protection to the facilities defined in section 4.1.1 through
4.1.4 of the Reliability Standard, regardless of whether the protection
systems provide primary or backup protection and regardless of their
physical location. Our interpretation is based on the fact that
protective relays are applied to protect specific system elements and,
it is consistent with approved Reliability Standards,\105\ the zones of
protection principle on which relaying schemes are designed,\106\ and
NERC's voluntary Beyond Zone 3 Review, which examined all primary and
backup protection systems.\107\
---------------------------------------------------------------------------
\105\ 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)).
\106\ Protective relays are applied to protect specific elements
within its zone of protection on the electric system. The ``zone of
protection'' principle is used to ensure that each element on the
electric system is provided, at most primary, and at least backup,
protection so that there are no unprotected areas.
\107\ NERC Comments at 13.
---------------------------------------------------------------------------
113. We also clarify that protective relays can be applied as back-
up protection in two different ways: They can be physically located at
the generator terminal on the low-voltage side of a generator step-up
transformer and provide backup protection for a Bulk-Power System
element (i.e., for a transmission line outside of the generator zone of
protection), as discussed in the NOPR, or provide back-up protection
for the generator and the step-up transformer (i.e., within the
generator zone of protection), as the commenters discuss. In this
Reliability Standard, the Commission is referring to the first type of
relays; i.e., relays that are applied to provide back-up protection to
Bulk-Power System elements and that would sense increased current flow
due to a fault on a Bulk-Power System transmission circuit. In the
NOPR, the Commission explained that distance relays physically located
at the generator terminal that are applied to protect Bulk-Power System
facilities must be coordinated with primary protection systems for a
transmission line and be set to see through \108\ the step-up
transformer, providing backup protection for un-cleared faults on the
Bulk-Power System. Consequently, these relays will sense increased
current flow and may trip on high load and therefore must also be set
pursuant to PRC-023-1. If the primary protection system of the
transmission line fails to operate, or does not operate within a
certain time, the backup protection operates and trips Bulk-Power
System elements that it is applied to protect.
---------------------------------------------------------------------------
\108\ To ``see through'' refers to a protective relay setting
where, based on the apparent impedance as measured by the relay, the
relay will detect faults beyond, i.e., ``see through,'' a bulk
electric system element.
---------------------------------------------------------------------------
114. Our statement that such relays are subject to the Reliability
Standard is not in conflict with the use of a protection system to
protect the generator/step-up transformer in the context of other
industry standards, such as IEEE Standard C37.102,\109\ or with the
exclusion in section 3.4 of Attachment A to PRC-023-1 of generator
relays that are susceptible to load. The relays that we referred to in
the NOPR, while they may be physically located at the generator
terminal or on the low-voltage side of the generator step-up
transformer, are applied to provide backup protection for Bulk-Power
System elements. This application is different from ``generator
relays,'' which are also physically located at the generator, but are
applied to protect the generator.
---------------------------------------------------------------------------
\109\ IEEE Standard C37.102 (IEEE Guide for AC Generator
Protection) provides generally accepted forms of relay protection
applied to protect the synchronous generator and its excitation
system.
---------------------------------------------------------------------------
E. Need To Address Additional Issues
115. In the NOPR, the Commission identified two additional issues
that the ERO must address to ensure Reliable Operation of the Bulk-
Power System: (1) Zone 3/zone 2 relays applied as remote circuit
breaker failure and backup protection; and (2) protective relays
operating unnecessarily due to stable power swings.
1. Zone 3/Zone 2 Relays Applied as Remote Circuit Breaker Failure and
Back-Up Protection
a. NOPR Proposal
116. In the NOPR, the Commission expressed concern about the impact
that
[[Page 16930]]
zone 3/zone 2 relays applied as remote circuit breaker failure and
backup protection can have on reliability when they operate without a
time delay or for non-fault conditions. The Commission explained that
if a zone 3/zone 2 relay detects a fault on an adjacent transmission
line within its reach, and the relay on the faulted line fails to
operate, the zone 3/zone 2 relay will operate as a backup and remove
the fault; when it does, however, it will disconnect both the faulted
transmission line and ``healthy'' facilities that should have remained
in service. The Commission noted that zone 3/zone 2 relays are
typically set to operate after a time delay in order to ensure
coordination of protection and avoid unnecessarily disconnecting
``healthy'' facilities.\110\
---------------------------------------------------------------------------
\110\ NOPR, FERC Stats. & Regs. ] 32,642 at P 50.
---------------------------------------------------------------------------
117. The Commission also explained that the large reach of a zone
3/zone 2 relay makes it susceptible to operating for certain non-fault
conditions, such as very high loading and large, but stable power
swings, because the current and voltage as measured by the impedance
relay may fall within the very large magnitude and phase setting of the
relay.\111\ The Commission cited the Task Force's finding that fourteen
345 kV and 138 kV transmission lines disconnected during the August
2003 blackout because of zone 3/zone 2 relays applied as remote circuit
breaker failure and backup protection,\112\ including several zone 2
relays in Michigan that overreached their protected lines by more than
200 percent and operated without a time delay.\113\ The Commission
noted that while these relays operated according to their settings, the
Task Force concluded that 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.\114\
---------------------------------------------------------------------------
\111\ Id. P 52.
\112\ Final Blackout Report at 80.
\113\ Id.
\114\ Id.
---------------------------------------------------------------------------
118. The Commission acknowledged NERC's claim 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.\115\ Nevertheless, given the Task Force's conclusions about
the role of zone 3/zone 2 relays in the August 2003 blackout, the
Commission proposed to direct the ERO to develop a maximum allowable
reach for zone 3/zone 2 relays applied as remote circuit breaker
failure and backup protection.\116\
---------------------------------------------------------------------------
\115\ See NERC Petition at 38-39.
\116\ NOPR, FERC Stats. & Regs. ] 32,642 at P 53.
---------------------------------------------------------------------------
b. Comments
119. NERC and other commenters argue that PRC-023-1 already
addresses the Commission's concerns because it establishes loadability
limits based on protection-zone-specific limitations, such as equipment
thermal ratings and maximum power transfer capability, for all load
responsive relays, independent of their application.\117\
---------------------------------------------------------------------------
\117\ See Consumers Energy, Dominion, Duke, Entergy, Exelon,
EEI, Oncor, PG&E, SCEG, Southern, TAPS.
---------------------------------------------------------------------------
120. EEI states that an entity will first develop protective relay
settings that ensure adequate protection of its facility or facilities
and then apply Requirement R1. EEI states that if the entity cannot
satisfy Requirement R1, it must change its relay scheme to accommodate
the need for protection and to comply with PRC-023-1.\118\ EEI
maintains that Requirement R1 addresses the Commission's concern in the
NOPR because no exemption is given to relays that are set to cover
adjacent lines in the event of breaker failure. EEI contends,
therefore, that PRC-023-1 does not need to identify any maximum reach
allowable outside of the impact on loadability. EEI further argues that
issues of protective relay settings that over reach adjacent lines and
trip with insufficient delay are coordination issues and not
transmission relay loadability issues. EEI adds that, if remote back-up
relays cannot provide adequate breaker failure coverage and still
comply with PRC-023-1, then local breaker failure relaying must be
applied.\119\
---------------------------------------------------------------------------
\118\ EEI at 19.
\119\ Id. at 20.
---------------------------------------------------------------------------
121. BPA explains that by complying with one of the sub-
requirements in Requirement R1 (R1.1 through R1.13), entities' zone 3/
zone 2 relay settings will be based on the real load carrying
requirements of the line to which they are applied, but will not
operate for allowable line loads. BPA argues that a blanket maximum
reach limit would nullify the thirteen sub-requirements in Requirement
R1, prevent entities from optimizing their relay settings for each
situation, and unnecessarily reduce protection. Exelon states that PRC-
023-1 allows entities to assess their relays' loadability based on the
most severe line ratings at severely depressed voltage, and either
includes a margin beyond these ratings or is based on the ability of a
circuit to actually carry a load given its length and/or location
within the system. Entergy asserts that maximum reaches are affected by
the inherent capabilities of the relays, such as where load
encroachment is present.
122. ATC argues that the Commission's proposal may put an
arbitrarily low loading limit on some transmission lines. ATC explains
that on a short transmission line, a relay setting of several times the
line's impedance would not limit the loading of the line, whereas on a
long transmission line the same impedance setting would limit loading.
ATC argues that a maximum allowable reach is immaterial because the
security of a relay's setting is determined by the relay's load-
sensitive trip point, together with an appropriate load margin with
respect to the maximum load carrying capability of the protected
transmission system element.
123. WECC maintains that the appropriate use of readily available
technology will completely addresses the Commission's concerns. WECC
observes that the relay operations identified by the Task Force and
referenced by the Commission occurred mostly with relays that used
traditional mho circle characteristics.\120\ WECC explains that the mho
relay characteristic always includes a substantial resistive reach (in
the direction of load, at least half the reactive reach) along with the
necessary reactive reach (in the direction of possible faults). WECC
states that in modern microprocessor-based relays, several different
methods are available to limit the relays' resistive (load) reach
without sacrificing the ability to detect remote faults (reactive
reach), including non-circular characteristic shapes (e.g., lens,
rectangle), offset mho, blinders, and specific load encroachment
elements.
---------------------------------------------------------------------------
\120\ ``Mho-circle'' refers to the circular operating
characteristic of a phase distance protection relay.
---------------------------------------------------------------------------
124. Many commenters, including NERC, assert that establishing a
shorter maximum reach for zone 3/zone 2 relays applied as remote
circuit breaker failure and backup protection may adversely impact
reliability. In general, these commenters assert that when the level of
backup protection is reduced, there is an increased probability that
faults will not be cleared and system stability will suffer.
125. Commenters also stress the problems associated with setting a
uniform maximum reach. Southern states that it would be difficult to
establish an arbitrary maximum reach that fits all system
configurations because the setting for a zone 3/zone 2 relay is based
on the location of the
[[Page 16931]]
relevant relay and the structure of the protection scheme for the
pertinent system. Duke argues that an arbitrary relay reach limit would
not provide the necessary protection flexibility to align protection
needs with all primary system configurations and electrical
characteristics. EEI and ITC argue that it is not technically possible
with current system configurations to enact the Commission's proposal
and maintain reliability and ensure fault detection. EEI states that
the electric industry's technically preferred approach is to set
specific fault conditions.
126. The PSEG Companies speculate that the Commission's proposal
will translate into a requirement to replace zone 3 relays with
expensive communication-based schemes. The PSEG Companies state that
such a requirement would be impractical and ineffective with respect to
facilities below 200 kV. Nevertheless, the PSEG Companies support
limits on the reach of zone 3/zone 2 relays for circuits that are truly
critical, provided that the circuits are identified through an open
process and their designation supported by a proper engineering
analysis by the Regional Entity.
c. Commission Determination
127. We decline to adopt the NOPR proposal and will not direct the
ERO to develop a maximum zone 3/zone 2 reach. After further
consideration, we agree with commenters, especially NERC and EEI, that
PRC-023-1, which interacts with existing FAC, IRO, and TOP Reliability
Standards while ensuring adequate circuit breaker failure protection,
sufficiently addresses the Commission's concern.
128. In its petition, NERC stated that the interactions between
PRC-023-1 and existing FAC, IRO, and TOP Reliability Standards require
entities and operators to establish limits for all system elements,
operate interconnected systems within these limits, take immediate
action to mitigate operation outside these limits, and set protective
relays to refrain from operating until the observed condition on their
protected element exceeds these limits.\121\ EEI maintains that
Requirement R1 addresses the Commission's concern because no exemption
is given to relays that are set to cover adjacent lines in the event of
breaker failure. EEI contends, therefore, that PRC-023-1 does not need
to identify any maximum reach allowable outside of the impact on
loadability. EEI adds that, if remote back-up relays cannot provide
adequate breaker failure coverage and still comply with PRC-023-1, then
local breaker failure relaying must be applied.
---------------------------------------------------------------------------
\121\ NERC Petition at 15-16.
---------------------------------------------------------------------------
129. We agree with NERC and EEI that if an entity chooses to use
remote breaker failure protection, it must comply with PRC-023-1 and
its protection settings, derived pursuant to PRC-023-1, must interact
with other relevant Reliability Standards to ensure Reliable Operation.
EEI asserts that if remote backup relays cannot provide adequate
breaker failure coverage and still comply with PRC-023-1, then local
breaker failure relaying must be applied. We agree. This assertion
addresses our concern that entities would continue to rely on the use
of remote breaker failure protection and simply comply with PRC-023-1
without ensuring whether: (i) it provides adequate circuit breaker
failure protection coverage; and (ii) that the limitation of remote
circuit breaker failure protection and the settings so derived to
comply with PRC-023-1 are reflected in the derivation of IROLs and SOLs
that are used in real time operations.
2. Protective Relays Operating Unnecessarily Due to Stable Power Swings
130. In the NOPR, the Commission stated that the cascade during the
August 2003 blackout was accelerated by zone 3/zone 2 relays that
operated because they could not distinguish between a dynamic, but
stable power swing and an actual fault. The Commission observed that
PRC-023-1 does not address stable power swings, and pointed out that
currently available protection applications and relays, such as pilot
wire differential, phase comparison and blinder-blocking applications
and relays, and impedance relays with non-circular operating
characteristics, are demonstrably less susceptible to operating
unnecessarily because of stable power swings. Given the availability of
alternatives, the Commission stated 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. The Commission explained that 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 requested comments
on whether it should direct the ERO to develop a new Reliability
Standard or a modification to PRC-023-1 that requires the use of
protective relay systems that can differentiate between faults and
stable power swings and phases out protective relay systems that cannot
meet this requirement.\122\
---------------------------------------------------------------------------
\122\ NOPR, FERC Stats. & Regs. ] 32,642 at P 60.
---------------------------------------------------------------------------
a. Comments
131. NERC opposes addressing stable power swings in a modification
to PRC-023-1. NERC argues that while it is possible to employ
protection systems that are immune from stable power swings, the
Commission should not require the use of these systems at the expense
of diminishing the ability of protective relays to dependably trip for
faults or detect unstable power swings. According to NERC, there are
two ways to prevent protective relays from operating during stable
power swings: (1) Select a protection system that will differentiate
between faults and stable power swings, but will not trip for any power
swing, such as current differential or phase comparison; or (2) utilize
an impedance-based protection system that relies on careful selection
of the protective relay trip characteristic, including shape (e.g., mho
circle, lens) and sensitivity, to differentiate between faults, stable
swings, and unstable swings. NERC adds that selection of the trip
characteristic requires coordination based on fault coordination and
transient stability studies between the protection system designer and
the transmission planner.
132. While NERC acknowledges that PRC-023-1 is designed to address
the steady-state aspects of relay loadability, it also claims that PRC-
023-1 has positive effects in relation to relays and stable power
swings. Specifically, the modifications required by PRC-023-1 to
increase steady state loadability necessarily decrease the likelihood
that relays will trip on stable power swings.
133. NERC cautions that it must carefully study and analyze the
relationship between stable power swings and protective relays, and
consult with IEEE and other organizations before developing a
Reliability Standard addressing stable power swings. NERC requests that
the Commission allow PRC-023-1 to remain focused on steady state relay
loadability and leave stable power swings to be specifically addressed
in a different Reliability Standard.
134. Other commenters agree with the concerns identified by the
Commission. None, however, think that the Commission should direct the
ERO to modify PRC-023-1 to address stable
[[Page 16932]]
power swings.\123\ Many commenters agree with NERC and urge the
Commission to allow the ERO to address stable power swings in a
different Reliability Standard, after the ERO has had the opportunity
to further study the issue. EEI and Southern argue that PRC-023-1
addresses the steady-state aspects of relay loadability, not transient
system conditions such as stable or unstable power swings. The PSEG
Companies reflect the view of many commenters when they argue that
issues related to stable power swings are too complex to be addressed
in PRC-023-1. Dominion adds that if the Commission did direct the ERO
to address stable power swings in PRC-023-1, the final implementation
of the Reliability Standard would be significantly delayed. TAPS argues
that the Commission should give due weight to NERC's decision not to
address stable power swings in PRC-023-1. APPA asserts that the
Commission can require only that the ERO examine the Commission's
concerns about stable power swings and cannot direct the ERO to
implement a specific solution.
---------------------------------------------------------------------------
\123\ See, e.g., EEI; APPA; PG&E; ATC; Ameren; BPA; Duke; Oncor;
and TAPS.
---------------------------------------------------------------------------
135. Several commenters challenge the Commission's reasoning and
assumptions in the NOPR. Exelon challenges the Commission's assertion
that 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, arguing that
it ignores many years of reliable and stable operation of mho-circle
relays. Exelon adds that it is unaware of any instance in the entire
history of its ComEd or PECO operating companies when mho-type distance
relays tripped because of a stable power swing, and that none of its
stability studies have ever identified lines that would trip on a
stable power swing.
136. ElectriCities, the MDEA Cities, and the Six California Cities
challenge the Commission's assertion that the use of protective relays
that cannot differentiate between faults and stable power swings is
mis-coordination of the protection system and is inconsistent with an
entity's obligations under existing Reliability Standards. In their
view, the Commission should not use this proceeding to interpret
existing Reliability Standards to require the use of specific
protection technologies and proscribe the use of others; ElectriCities
asserts that interpreting Reliability Standards not at issue may
violate the Administrative Procedure Act.\124\
---------------------------------------------------------------------------
\124\ 5 U.S.C. 551, et seq.
---------------------------------------------------------------------------
137. Consumers Energy disagrees with the Commission's assertion
that stable power swings contributed to the cascade in the August 2003
blackout. Consumers Energy states that it extensively studied the
events discussed in the NOPR and concluded that communications-based
relay systems operated because of the extremely heavy reactive power
consumption of the lines, not stable power swings. Consumers Energy
states that its studies also show that relay systems designed to be
less susceptible to stable power swings would still have operated under
these conditions, as the extreme reactive power consumption appeared to
both terminals of each line as an internal fault.
138. WECC claims that PRC-023-1 provides indirect, but highly
effective protection against stable power swings. WECC asserts that the
real problem that occurred during the August 2003 blackout was that
zone 3/zone 2 relays operated and disconnected facilities because of
high loading. WECC argues that if those zone 3/zone 2 trips had been
prevented, significant system oscillations would not have occurred and
``healthy'' transmission lines would not have unnecessarily tripped.
WECC asserts that PRC-023-1 is specifically designed to prevent zone 3/
zone 2 trips due to high loading. EEI argues that PRC-023-1 is ``well
suited'' to prevent the unnecessary operation of relays during stable
power swings because as relay loadability is increased, the proper
response to stable power swings is enhanced.
139. Several commenters challenge the Commission's assumption that
preventing relays from operating due to stable power swings will
improve reliability. TAPS explains that an important secondary function
of protective relaying is protecting equipment and safety in the event
of multiple or extreme contingencies. TAPS states that the power system
is operated to account for single and double contingencies, but that
extreme contingencies can occur and overload facilities to well beyond
their emergency ratings. TAPS contends that it is impractical to rely
on operators to manually operate the system beyond single and double
contingencies, so automatic equipment is needed to protect the system
when extreme contingencies occur. TAPS maintains that while impedance/
distance relays are susceptible to operating for stable power swings,
they are often the only protection for facilities loaded beyond
emergency ratings. TAPS argues that the Commission's proposal would
reduce reliability because it would expose the system to longer-term
outages due to equipment damage. TAPS also claims that overloading due
to multiple or extreme contingencies can create the same safety issues
the Commission discussed in the NOPR with respect to sub-requirement
R1.10.
140. E.ON argues that the Commission may have elevated the
operational reliability of the bulk electric system over public safety
and the transmission asset owner's interest in ensuring that its assets
remain in working order and available for service. E.ON explains that
relay settings must ensure the maintenance of minimum vertical safety
clearances, and that modifying relaying schemes to accommodate non-
fault related transient overloads might leave system elements exposed
to excessive loading longer than is prudent. E.ON further explains that
because transmission facilities are located in diverse environments, it
is appropriate to maintain a specified vertical line clearance at the
maximum conductor temperature for which the line is designed to
operate. E.ON states that what the Commission described as a
``technological impediment'' may be a desired design feature intended
to address unique equipment protection issues or public safety
concerns.
141. Exelon asserts that phasing out step distance relays with mho
circle operating characteristics could leave the electric system
without any reliable backup for transmission lines with failed
communication or other equipment failures, thereby exposing the system
to faults that cannot be cleared and potentially resulting in larger
outages and/or equipment damage. TAPS adds that the Commission's
proposal would result in the loss of zone 3/zone 2 relays as back-up
protection in the event of a stuck breaker and/or a failure of a
transfer trip scheme for a stuck breaker.
142. The PSEG Companies speculate that the post-blackout relay
mitigation programs conducted by NERC may have already mitigated the
unexpected tripping of the transmission lines during the August 2003
blackout. The PSEG Companies add that it is possible that the only
reason the blackout stopped was because these lines unexpectedly
tripped. The PSEG Companies assert that the approach to stable power
swings should be all encompassing and include the development and
implementation of ``islanding'' strategies in conjunction with out-of-
step blocking (or tripping) requirements.
[[Page 16933]]
143. Several commenters dispute the virtues of the protection
schemes discussed by the Commission in the NOPR. Ameren states that, in
its experience, many of the applications identified by the Commission
in the NOPR are less reliable than the step distance and directional
comparison methods used in distance relays. Duke casts doubt on
manufacturers' claims that newer relay technology is able to
differentiate between stable power swings and out-of-step conditions,
pointing out that much of the newer technology is essentially the same
as traditional out-of-step relay blocking schemes with variable timers.
Duke also observes that some new protection systems still require
relays to be set to operate on high load conditions and block tripping
for a fault during a stable power swing. EEI states that the protection
schemes cited by the Commission are prone to mis-operation due to loss
of communication or timing differences in a transmit-and-receive
communication path. EEI explains that on September 18, 2007, the
protection schemes identified by the Commission actually created a
major disturbance in the MRO region due to problems with communication
circuits.\125\
---------------------------------------------------------------------------
\125\ EEI at 21-22.
---------------------------------------------------------------------------
144. EEI argues that subject matter experts in the electric
industry have found that the protection schemes cited by the Commission
in the NOPR are significantly more difficult to install and maintain
than step distance and directional comparison schemes using distance
relays. EEI states, for example, that while line differential relays
have been reliable when applied over fiber communications systems, the
necessary schemes are expensive to install. Ameren adds that line
differential relays are not as reliable as phase distance relays, which
would still need to be installed to backup the communications system.
Ameren also states that installation of fiber optics on existing
transmission lines would require lengthy construction delays, and
therefore create a reliability risk and delay compliance with PRC-023-
1.
145. EEI and Ameren also point out the limitations of out-of-step
tripping and power swing blocking. They explain that in a 2005 report,
the IEEE Power System Relaying Committee found that out-of-step
tripping and power swing blocking cannot be set reliably under extreme
multi-contingency conditions where the trajectories of power swings are
unpredictable, because they must be set based on specific system
contingencies and the results of stability simulations.
146. Exelon argues that the technology identified by the Commission
may not be helpful in a situation like the August 2003 blackout. Exelon
explains that experienced relay protection engineers can apply the
technology to distinguish between stable and unstable power swings in
the cases of Category A, B, C and even some Category D contingencies as
detailed in the TPL Reliability Standards, but that these are discrete
contingencies that can be simulated with a great deal of certainty.
Exelon states that simulating the types of swings that occurred during
the August 2003 blackout would involve many scenarios, occurring in
different possible sequences. Exelon claims that it is virtually
impossible to accurately predict the exact sequence of events for major
disturbances involving extreme events, and that without accurate
simulations of the ``right'' disturbances, replacing relays would not
provide any benefit.
147. WECC and Tri-State make the related point that there were at
least fourteen line outages before the stable swings began in the
August 2003 blackout, and that it is unlikely that the multiple
contingency scenarios that developed would ever have been studied under
the current TPL Reliability Standards. WECC adds that even if the TPL
Reliability Standards required prior study and relay coordination for
such extensive outages, it is entirely plausible that the power swing
blocking settings appropriate for a system that included 2 or 3
contingencies would not work appropriately for the same system after 14
or 40 outages.
148. Multiple commenters claim that the Commission's proposal would
place an undue and unnecessary financial hardship on utilities because
it would require significant expenditures and an exceptional amount of
skilled labor without commensurate benefits. Exelon argues that any
type of a proposed phase-out would affect a majority of the relays in
North America. With respect to its PECO and ComEd operating companies,
Exelon estimates that it would cost PECO approximately $45 million to
comply for roughly 180 terminals between 230 kV and 500 kV ($250,000
per terminal) and 33 percent more if the phase-out applied to 138 kV
lines. As for ComEd, Exelon estimates that it would cost approximately
$65 million to comply for roughly 260 terminals between 345 kV and 765
kV, and three times more if the phase-out applied 138 kV lines.
Portland General states that it would cost $6 million to replace its 40
relays. TAPS points out that Order No. 672 states that NERC may
consider the cost of compliance when developing a Reliability Standard,
provided that the Standard does not reflect the ``lowest common
denominator.'' TAPS argues that PRC-023-1 does not reflect the ``lowest
common denominator.''
149. EEI argues that the Commission's proposal will require the
unreasonable removal of a large number of electromechanical relays that
effectively function, and that electric utilities should replace
electromechanical relays only when necessary. Oncor argues that is
unnecessary to mandate a phase out because as utilities upgrade their
protection systems on a voluntary basis they will eliminate relays that
cannot differentiate between faults and stable power swings. TAPS
states that the Commission's proposal, in combination with its proposal
to eliminate the exclusions in Attachment A of PRC-023-1 (particularly
subsection (3.1)), would require redundant high speed protective
systems for every transmission line, even when they are not needed for
critical clearing time purposes. TAPS also argues that requiring the
addition of new protective relay systems runs up against the
prohibitions in sections 215 (a)(3) and (i)(2) of the FPA on
Reliability Standards that require the enlargement of facilities or the
addition of generation or transmission capacity.
b. Commission Determination
150. We will not direct the ERO to modify PRC-023-1 to address
stable power swings. However, because both NERC and the Task Force have
identified undesirable relay operation due to stable power swings as a
reliability issue, we direct the ERO to develop a Reliability Standard
that requires the use of protective relay systems that can
differentiate between faults and stable power swings and, when
necessary, phases out protective relay systems that cannot meet this
requirement. We also direct the ERO to file a report no later than 120
days of this Final Rule addressing the issue of protective relay
operation due to power swings. The report should include an action plan
and timeline that explains how and when the ERO intends to address this
issue through its Reliability Standards development process.
151. According to the NERC System Protection and Control Task
Force, it is a well established principle of protection that Bulk-Power
System elements, such as generators, transmission lines, transformers,
and DC transmission or shunt devices, should not trip inadvertently for
expected and potential non-fault loading conditions,
[[Page 16934]]
including normal and emergency loading conditions and stable power
swings.\126\ Before Congress' directive in section 215 of the FPA to
establish mandatory and enforceable Reliability Standards, this
reliability principle was considered good utility practice and was
documented in the voluntary NERC Planning Standards as one of the
System and Protection and Control Transmission Protection Systems
Guides.\127\ However, the ERO has not yet proposed to translate this
principle into a mandatory and enforceable directive by including it in
a Reliability Standard.
---------------------------------------------------------------------------
\126\ NERC Planning Committee, System Protection and Control
Task Force, ``Relay Loadability Exceptions--Determination and
Application of Practical Relaying Loadability Ratings,'' Version
1.2, at 3 (Aug. 8, 2005).
\127\ See NERC Planning Standards, Section III: System and
Protection and Control, Part A: Transmission Protection Systems,
G.12 (1997) (``Generation and transmission protection systems should
avoid tripping for stable power swings on the interconnected
transmission systems.''). Under the voluntary planning standards and
operating policies, a ``Guide'' described good planning practices
and considerations.
---------------------------------------------------------------------------
152. Additionally, as we explained in the NOPR, while zone 3/zone 2
relays operated during the August 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.\128\ The Task Force also identified
dynamic power swings and the resulting system instability as the reason
why the cascade spread.\129\ Since PRC-023-1 does not address relays
operating unnecessarily because of stable power swings, we are
concerned that relays set according to PRC-023-1 remain susceptible to
problems like those that occurred during the August 2003 blackout.
---------------------------------------------------------------------------
\128\ NOPR, FERC Stats. & Regs. ] 32,642 at P 58.
\129\ See Final Blackout Report at 81-82.
---------------------------------------------------------------------------
153. While we recognize that addressing stable power swings is a
complex issue, we note that more than six years have passed since the
August 2003 blackout and there is still no Reliability Standard that
addresses relays tripping due to stable power swings. Additionally,
NERC has long identified undesirable relay operation due to stable
power swings as a reliability issue. Consequently, pursuant to section
215(d)(5) of the FPA, we find that undesirable relay operation due to
stable power swings is a specific matter that the ERO must address to
carry out the goals of section 215, and we direct the ERO to develop a
Reliability Standard addressing undesirable relay operation due to
stable power swings.
154. We note that NERC stated in its petition that PRC-023-1
interacts with several existing FAC, IRO, and TOP Reliability
Standards, and that these interactions require limits to be established
for all system elements, interconnected systems to be operated within
these limits, operators to take immediate action to mitigate operation
outside of these limits, and protective relays to refrain from
operating until the observed condition on their protected element
exceeds these limits.\130\ We agree, and add that entities must also
validate protection settings set pursuant to PRC-023-1 through: (1)
Using the settings as an input into the valid assessments required for
compliance with the TPL Reliability Standards for contingencies; (2)
including the settings in the derivation of SOLs and IROLs; and (3)
complying with the TOP, IRO, and FAC Reliability Standards for Category
B contingencies, and for the subset of multiple contingencies (if any)
identified in TPL-003 that result in stability limits identified by the
planning authority. These steps will ensure Reliable Operation until
the ERO develops the new Reliability Standard addressing unnecessary
relay operation due to stable power swings.
---------------------------------------------------------------------------
\130\ NERC Petition at 15-16.
---------------------------------------------------------------------------
155. Although we do not direct the ERO to modify PRC-023-1 to
address stable power swings, we disagree with those commenters who
suggest that relay performance during stable power swings is outside
the scope of relay loadability. Reliability Standard PRC-023-1 was
developed by industry experts using well thought-out guidelines based
on static system conditions. These guidelines apply only to the
situation in which the electric system after a disturbance has returned
to a steady state condition. This means that currents and voltages on
Bulk-Power System elements vary with a large degree of predictability.
Under this scenario, compliance with PRC-023-1 will prevent relays from
inadvertently tripping because of increases in static loadings; hence,
the term ``loadability.''
156. However, protective relays will respond to real-time system
conditions, regardless of whether they are set for static loadings
(loadability) or dynamic loadings, such as stable power swings. During
transient conditions, a protective relay set assuming steady-state
system conditions will measure the prevailing voltage and current
quantities resulting from a stable power swing, and if its trajectory
falls within the relay settings (reach and time delay) so derived from
PRC-023-1, it will operate and inadvertently trip the healthy Bulk-
Power System element it is protecting. Consequently, the relay may
operate for transient conditions, even if set pursuant to PRC-023-1.
Thus, relay operation because of stable power swings is within the
scope of relay loadability and must be considered when the relay is set
to ensure Reliable Operation.
157. Exelon states that its stability studies for ComEd and PECO
have never identified lines that would trip on stable power swings.
There are two potential reasons why not: (1) Exelon's protection
systems are designed so that it is unnecessary to establish longer
reach settings for protective relays; or (2) its electric systems
consist primarily of short transmission lines.
158. Initially, we note that ComEd and PECO may have historically
adopted a good utility practice in protection that requires two groups
(both of equivalent high speed) of redundant and duplicated
communications-based protection systems for each high voltage line
while relying on the use of local breaker failure protection.\131\ If
this were the case, they would not need to set their relays to
overreach by large margins to provide remote circuit breaker failure
and backup protection because they designed around the problem. In
addition, the high voltage lines in ComEd and PECO may be relatively
short. Electric systems comprised of long transmission lines are more
likely to experience larger stable power swings than those comprised of
short transmission lines. These two factors--relative short protection
reach in their Zone 1 and Zone 2 relays due to application of more
sophisticated protection systems and not relying on the use of remote
breaker failure protection, as well as, smaller stable power swings due
to shorter transmission lines--are likely to be the key reasons why
they have never identified lines that would trip on stable power
swings.
---------------------------------------------------------------------------
\131\ See NERC Planning Standards, Section III: System and
Protection and Control, Part A: Transmission Protection Systems, G.5
(1997) (``Physical and electrical separation should be maintained
between redundant protection systems, where practical, to reduce the
possibility of both systems being disabled by a single event or
condition.''). While this is considered a good utility practice and
used worldwide, it may not have necessarily been used by other
entities in the past and is currently not required by any
Reliability Standard.
---------------------------------------------------------------------------
159. We find unpersuasive Consumers Energy's claim that heavy
reactive power consumption, not stable power swings, contributed to the
cascade during the August 2003 blackout. In the Final Blackout Report,
the Task Force
[[Page 16935]]
addressed this issue and concluded that, as the cascade progressed
beyond Ohio, it spread due not to insufficient reactive power and a
voltage collapse, but because of dynamic power swings and the resulting
system instability.\132\ While extreme reactive power consumption may
have resulted in the operation of some communications-based relays, the
Final Blackout Report confirms that zone 3/zone 2 relays without
communications or an uncoordinated time delay operated unnecessarily
when they recognized dynamic, but stable, power swings as a fault. As
the Task Force explained, this undesirable operation contributed to the
cascade and the spread of the blackout.
---------------------------------------------------------------------------
\132\ Final Blackout Report at 81.
---------------------------------------------------------------------------
160. WECC argues that PRC-023-1 provides indirect protection
against stable power swings because it prevents relays from tripping
due to high loading, and that this protection could have prevented the
tripping of the zone 3/zone 2 relays during the blackout and prevented
the oscillations that caused ``healthy'' transmission lines to
unnecessarily trip. While we agree that increasing loadability by
applying the settings set forth in PRC-023-1 decreases the likelihood
of relays tripping on load, it does not necessarily decrease the
likelihood of zone 3/zone 2 relays applied as remote circuit breaker
failure and backup protection tripping on stable power swings and would
not have prevented the trips that spread the August 2003 blackout. Zone
3/zone 2 relays applied as remote circuit breaker failure and backup
protection require large protective reach settings. The protective
reach setting is determined by the apparent impedance of the system as
measured by the relay. When the apparent impedance as measured by the
relay falls within the setting of the relay, the relay will operate
after its set time delay. While a fault typically moves through the
characteristic of a relay reach setting very fast, the speed at which a
power swing moves through the characteristic of a relay reach setting
is typically much slower. When a power swing occurs, it is the time
that it takes the power swing to pass through the characteristic of the
relay's protective reach setting that makes the relay susceptible to
operation. As we explained in the NOPR, the Final Blackout Report found
that several zone 2 relays applied as remote circuit breaker failure
and backup protection were set to overreach their protected lines by
more than 200 percent without any time delay.\133\ When the dynamic,
yet stable, power swings occurred prior to system cascade, these relays
operated unnecessarily.\134\
---------------------------------------------------------------------------
\133\ Id. at 80.
\134\ Id. at 82.
---------------------------------------------------------------------------
161. The PSEG Companies suggest that NERC's post-blackout relay
mitigation programs may have addressed the unexpected tripping of lines
that occurred during the August 2003 blackout, and that it is possible
that the only reason the blackout stopped was because these lines
unexpectedly tripped. We disagree, based on two facts documented in the
Final Blackout Report. First, the unexpected tripping of these lines in
Ohio and Michigan accelerated the geographic spread of the cascade
instead of stopping it.\135\ Second, relays on long lines that are not
highly integrated into the electrical network, such as the Homer City-
Watercure and the Homer City-Stolle Road 345-kV lines in Pennsylvania,
tripped quickly and split the grid between the sections that blacked
out and those that recovered without further propagating the cascade.
We also disagree with the PSEG Companies' assertion that NERC's post-
blackout relay mitigation programs may have addressed the unexpected
tripping of lines that occurred during the August 2003 blackout for two
main reasons: (i) The programs did not include on a general basis sub-
200 kV facilities that are considered as critical or operationally
significant facilities; \136\ and (ii) the programs did not explicitly
address inadvertent tripping on non-faulted facilities due to stable
power swings.
---------------------------------------------------------------------------
\135\ Id. at 80.
\136\ The Beyond Zone 3 review included sub-200 kV facilities on
a limited basis.
---------------------------------------------------------------------------
162. The PSEG Companies also assert that the Commission's approach
to stable power swings should be inclusive and include ``islanding''
strategies in conjunction with out-of-step blocking or tripping
requirements. We agree with the PSEG Companies and direct the ERO to
consider ``islanding'' strategies that achieve the fundamental
performance for all islands in developing the new Reliability Standard
addressing stable power swings.
163. We also clarify that our directive does not in any way involve
a tradeoff between reliability and public safety as suggested by E.ON's
concerns about the maintenance of minimum vertical safety clearances
and TAPS's concerns about modifying relaying schemes to accommodate
non-fault-related transient overloads. First, while the maintenance of
minimum vertical safety clearances for personnel safety consideration
is outside of Commission jurisdiction, the development of line ratings
consistent with FAC-008-1 (Facility Ratings Methodology) must include
the limiting factors, such as line design, ambient conditions and
system loading conditions. For these ratings to be valid there must be
adequate clearances between line conductors and surrounding objects to
prevent flashover in addition to maintaining adequate vertical
clearance from the ground. Reliability Standard FAC-003-1 Requirement
R1.2.1 also includes a provision for ``worker approach distance
requirements'' as part of the minimum clearances which include vertical
safety clearance. Therefore, we do not see how our directive would in
any way involve a tradeoff between reliability and safety as these are
addressed separately and interactively between the relevant Reliability
Standards.
164. Second, we do not see how the Commission's goal of avoiding
inadvertent tripping of non-faulted Bulk-Power System elements due to
stable power swings can be interpreted as requiring modifying relaying
schemes to accommodate non-fault related transient overloads, as TAPS
claims. In addition to our explanation above, NERC stated in its
petition, and we agree, that PRC-023-1 interacts with existing FAC,
IRO, and TOP Reliability Standards; these interactions require limits
to be established for all system elements, interconnected systems to be
operated within these limits, operators to take immediate action to
mitigate operation outside of these limits (i.e., overloads), and
protective relays to refrain from operating until the observed
condition on their protected element exceeds these limits.\137\ In
addition, each planning authority and transmission planner is required
to demonstrate through a valid assessment only that its portion of the
interconnected electric system is evaluated for the risks and
consequences of such extreme, multi-contingency events and for
corrective actions. For these reasons, we also reject TAPS's comments
that the NOPR proposal would create safety issues due to overloading
from multiple or extreme contingencies. If protection systems already
respect safety issues, they will not be affected by following the
evaluation of these extreme contingencies.
---------------------------------------------------------------------------
\137\ NERC Petition at 15-16.
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165. We also disagree with commenters' claims that our directive
could harm reliability. Exelon asserts that phasing out step distance
relays with mho circle operating characteristics could leave the
electric
[[Page 16936]]
system without any reliable backup for transmission lines with failed
communication or other equipment failures, thereby exposing the system
to faults that cannot be cleared and potentially resulting in larger
outages and/or equipment damage. TAPS adds that the Commission's
proposal would result in the loss of zone 3/zone 2 relays as back-up
protection in the event of a stuck breaker and/or a failure of a
transfer trip scheme for a stuck breaker.
166. Exelon incorrectly interprets our statement that ``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'' as a proposal
for ``leaving the electric system without any reliable backup for
transmission.'' TAPS' similar assertion implies the same. We disagree
that the Commission's proposal would result in the loss of relays as
back-up protection. Our statement merely points out the fundamentals
required for Reliable Operation under currently approved Reliability
Standards. As we state in the previous discussion, PRC-023-1 interacts
with existing FAC, IRO, and TOP Reliability Standards to ensure
Reliable Operation; these interactions require limits to be established
for all system elements, interconnected systems to be operated within
these limits, operators to take immediate action to mitigate operation
outside of these limits, and protective relays to refrain from
operating until the observed condition on their protected element
exceeds these limits. Protection relays include primary and backup
relays. If zone 2/zone 3 relays are used by entities as part of their
protection systems designed to achieve the system performance, they can
remain as backup protection as long as they do not inadvertently trip
non-faulted facilities due to stable power swings.
167. Several commenters dispute the virtues of the protection
schemes discussed by the Commission in the NOPR. In general, these
commenters argue that the applications identified by the Commission in
the NOPR are less reliable than the step distance and directional
comparison methods used in distance relays. We clarify that the
protection systems discussed in the NOPR are merely examples of systems
that can differentiate between faults and stable power swings. We leave
it to the ERO to determine the appropriate protection systems to be
discussed in the new Reliability Standard through application of its
technical expertise.
168. Some commenters argue that the technology identified by the
Commission may not be helpful in a situation like the August 2003
blackout because that event involved so many contingencies that it
would be almost impossible to simulate and thus unlikely to be studied
under the TPL Reliability Standards. We realize that relays cannot be
set reliably under extreme multi-contingency conditions covered by the
Category D contingencies of the TPL Reliability Standards. In fact,
Reliability Standard TPL-004-0 requires the planning authority and
transmission planner to demonstrate through a valid assessment that its
portion of the interconnected electric system is evaluated only for the
risks and consequences of such events; it does not require corrective
actions. We recognize that, because of the operating characteristic of
the impedance relay, regardless of whether a power swing is stable or
unstable, the relay may potentially operate under Category D
contingencies. Thus, the NOPR proposed alternative protection
applications and relays that are less susceptible to transient or
dynamic power swings. This is consistent with Order No. 693, where the
Commission stated that it is not realistic to expect the ERO to develop
Reliability Standards that anticipate every conceivable critical
operating condition applicable to unknown future configurations for
regions with various configurations and operating characteristics.\138\
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\138\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1706.
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169. Some commenters oppose a new Reliability Standard because they
are concerned that it would require the removal of a large number of
electro-mechanical relays that are in service and functioning today.
Likewise, other commenters argue that the cost of phasing out
protection systems that cannot distinguish between faults and stable
power swings is excessive. While we appreciate these concerns, they are
not persuasive reasons to reconsider our decision to direct the ERO to
develop a Reliability Standard addressing undesirable relay operation
due to stable power swings. In this Final Rule, we have explained why a
relay's inability to distinguish between actual faults and stable power
swings is a specific matter that the ERO must address in order to carry
out the goals of section 215 of the FPA, in part by showing how such
relays contributed to the spread of the August 2003 blackout. The fact
that many such relays are in current use does not mitigate the threat
they pose to Reliable Operation or change the role they played in
spreading the August 2003 blackout. Moreover, while we direct the ERO
to develop a Reliability Standard that phases out such relays where
necessary if they do not meet the reliability goal, the ERO is free to
develop an alternative solution to our reliability concerns regarding
undesirable relay operation due to stable power swings, provided that
it is an equally effective and efficient approach.\139\
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\139\ Id. P 186.
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170. Because we direct the ERO to develop the new Reliability
Standard in this Final Rule, it would be premature for the Commission
to now rule on issues related to the cost of the new Standard. In the
first place, the Reliability Standard is not yet written; the ERO has
not yet worked out the details of a phase-out, or even decided if it
will propose a phase-out or some other equally effective and efficient
solution to the Commission's reliability concerns. It is impossible for
the Commission to evaluate the costs of a proposal that has not yet
been developed, let alone one that has not has yet been presented to
the Commission. Entities will have the opportunity to raise their cost
concerns throughout the Reliability Standards development process and
before the Commission when NERC submits the new Reliability Standard
for Commission approval. As a general matter, however, we repeat our
statement in Order No. 672: Proposed Reliability Standards must not
simply reflect a compromise in the ERO's Reliability Standard
development process based on the least effective North American
practice--the so-called ``lowest-common denominator''--if such practice
does not adequately protect Bulk-Power System reliability.\140\ While a
Reliability Standard may take into account the size of the entity that
must comply and the costs of implementation, the ERO should not propose
a ``lowest common denominator'' Reliability Standard that would achieve
less than excellence in operating system reliability solely to protect
against reasonable expenses for supporting vital national
infrastructure.\141\ The Commission has also explained that the
Reliability Standard development process should consider, at a high
level, the potential costs and other risks to society of a Bulk-Power
System failure if action is not taken to establish and implement a new
or modified Reliability Standard in response to previous blackouts and
the
[[Page 16937]]
economic impacts associated with such blackouts.\142\
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\140\ Order No. 672, FERC Stats. & Regs. ] 31,204 at P 329.
\141\ Id. P 330.
\142\ ERO Rehearing Order, 117 FERC ] 61,126 at P 97.
---------------------------------------------------------------------------
171. We also disagree with TAPS's claim that the Commission's
proposal, in combination with its proposal to eliminate the exclusions
in Attachment A of PRC-023-1 (particularly subsection 3.1), would
require redundant high speed protective systems for every transmission
line, even when they are not needed for critical clearing time
purposes. As we have explained previously in this Final Rule, the TPL
Reliability Standards require annual system assessments to determine if
the system meets the desired system performance requirement established
by the TPL Standards. This assessment includes the interaction of
approved Reliability Standards such as, PRC, IRO, and TOP. If an entity
is not able to achieve the desired system performance, consistent with
the TPL Reliability Standards, corrective action plans must be
developed and implemented. Thus, it is left to the entity to determine
how best to meet desired system performance when it develops its
corrective action plans; contrary to TAPS's argument, our directives in
this Final Rule do not require entities to adopt redundant high speed
protective systems for every transmission line as a specific corrective
action plan.
172. Finally, we reject TAPS's assertion that requiring entities to
use protection systems that can distinguish between faults and stable
power swings violates sections 215(a)(3) and (i)(2) of the FPA, which
prohibit the Commission from requiring in a Reliability Standard the
enlargement of facilities or the addition of generation or transmission
capacity. Replacing a protection system that does not ensure Reliable
Operation in this instance is necessary to achieve the goals of the
statute and does not equate to an expansion of facilities or the
construction of new generation or transmission capacity.
173. In sum, we adopt the NOPR proposal and direct the ERO to
develop a new Reliability Standard that prevents protective relays from
operating unnecessarily due to stable power swings by requiring the use
of protective relay systems that can differentiate between faults and
stable power swings and, when necessary, phases-out relays that cannot
meet this requirement. NERC requests that the Commission allow PRC-023-
1 to remain focused on steady state relay loadability and leave stable
power swings to be specifically addressed in a different Reliability
Standard. We agree that this is a reasonable approach. Meanwhile, to
maintain reliability, the Commission expects entities to continue to
include the effects of protection settings in TPL and TOP assessments
for future systems and in the determination of IROLs and SOLs.\143\
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\143\ Requirement R1.3.10 of Reliability Standard TPL-002-0
requires that a valid assessment shall include, among other things,
the effects of existing and planned protection systems. Requirement
R6 of Reliability Standard TOP-002-0 requires that, as a minimum
criterion, the bulk electric system is planned and operated to
maintain reliable operation for the single contingency loss of any
transmission facility. In Order No. 693, the Commission explained
that ``[i]n deriving SOLs and IROLs, moreover, the functions,
settings, and limitations of protection systems are recognized and
integrated.'' Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1435.
---------------------------------------------------------------------------
F. Requirement R1
174. Requirement R1 directs each subject entity to set its relays
according to one of the criteria prescribed in sub-requirements R1.1
through R1.13. In the NOPR, the Commission expressed concerns about the
implementation of three of these criteria: sub-requirements R1.2,
R1.10, and R1.12. In its comments, Palo Alto raised concerns about sub-
requirement R1.1.
1. Sub-Requirement R1.1
175. 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.
a. Comments
176. Palo Alto states that, in the interest of maximum reliability,
many municipal utilities install lines and transformers rated to handle
the worst-case emergency load, i.e., the load resulting from the
failure of an adjacent line or transformer. Palo Alto explains that
load-sensitive overcurrent relays are typically set between 115 and 125
percent of the highest line or equipment rating, and argues that
changing these settings to comply with sub-requirement R1.1 will result
in longer fault clearing times and unnecessarily compromise line and
transformer protection. Palo Alto adds that longer fault clearing times
could result in increased arc flash exposure. Palo Alto recommends that
the Commission direct NERC to revise sub-requirement R1.1 to state that
transmission relays can be set to not operate at or below 150 percent
of the transmission line/transformer rating instead of the highest
seasonal facility rating of a circuit, or at 120 percent of the maximum
expected emergency load on the transmission line or transformer.
b. Commission Determination
177. Palo Alto identifies a technical disagreement with sub-
requirement R1.1. We expect such technical disagreements to be resolved
either in the Reliability Standards development process or by the
disagreeing entity requesting an exception from NERC. Moreover, giving
``due weight'' to the technical expertise of the ERO, we find no reason
to direct a change to sub-requirement R1.1.
2. Sub-Requirement R1.2
178. Sub-requirement R1.2 requires relays to be set not to operate
at or below 115 percent of the highest seasonal 15-minute facility
rating of a circuit. A footnote attached to sub-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.''
a. NOPR Proposal
179. In the NOPR, the Commission expressed concern that sub-
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.''
\144\ The Commission explained 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 sub-requirement R1.2. In order to avoid confusion and
protect reliability, the Commission proposed to direct the ERO to
revise sub-requirement R1.2 to give transmission operators the same
amount of time as in Reliability Standard TOP-004-1; develop a new
requirement that transmission owners, generation owners, and
distribution providers give their transmission operators a list of
transmission facilities that implement sub-requirement R1.2; or propose
an equally effective and efficient way to avoid the potential conflict.
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\144\ See Reliability Standard TOP-004-1, Requirement R4.
---------------------------------------------------------------------------
b. Comments
180. NERC urges the Commission to adopt sub-requirement R1.2
without directing a change. NERC states that the
[[Page 16938]]
purpose of the footnote is to inform the user that, if it decides to
implement sub-requirement R1.2, it must have a procedure that operators
implement and follow. NERC states that some system operators use a 15-
minute rating during system contingencies, which is a more stringent
requirement than that established in TOP-004-1. NERC also claims that
use of the 15-minute rating to establish loadability reflects a
commitment on the part of the entity to operate to the 15-minute rating
and to respond to rating violations within the 15 minutes because the
entity can use the 15-minute rating only if it has calculated and
published it for use in real-time operations.\145\
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\145\ NERC Comments at 28.
---------------------------------------------------------------------------
181. Oncor states that the Commission's concerns seem reasonable
and that a simple solution to the conflict would be to provide system
operators with a copy of those lines that have a 15-minute rating along
with the 30-minute rating of transmission lines as described in TOP-
004-1.\146\ IESO and Hydro One argue that if the Commission acts on its
proposal, creating a new requirement is the preferred approach in order
to avoid having a requirement specified in one Reliability Standard
actually applying to another Standard.
---------------------------------------------------------------------------
\146\ Oncor at 5.
---------------------------------------------------------------------------
182. Some commenters maintain that entities that use the 15-minute
rating are fully capable of operating within this constraint. Duke
explains that transmission operators are trained to operate the system
within the ratings established and communicated to them pursuant to
FAC-009-1, and adds that reliability coordinators, planning
authorities, transmission planners, and transmission operators already
receive these ratings pursuant to Requirements R1 and R2 of FAC-009-1.
Southern states that general industry practice, which is reflected in
Reliability Standard TOP-004-1, is to return the electric system to a
normal and reliable state in less than 30 minutes.
183. Several commenters challenge the Commission's claim that there
is a conflict between PRC-023-1 and TOP-004-1 and that transmission
operators might conclude that they have 30 minutes to restore the
system to normal when in fact they have only 15 minutes because the
relay settings for certain transmission facilities have been set to
operate at the highest seasonal 15-minute rating in accordance with
sub-requirement R1.2. As an initial matter, Dominion points out that
the Commission's statement mischaracterizes sub-requirement R1.2;
rather than allow for relays to operate at the 15-minute rating, sub-
requirement R1.2 specifies that relays must be set so that they do not
operate at or below 115 percent of the 15- minute rating. APPA, Ameren,
BPA, Dominion, EEI, and WECC further explain that sub-requirement R1.2
does not establish a time limit before relays trip; instead, it
specifies the level of loading used to develop the relay's setting. In
other words, according to these commenters, the 15-minute rating does
not mean that the relays will trip after 15 minutes. APPA clarifies
that 15 minutes is the time that the facility ratings methodology has
determined the line can safely be loaded at that level. BPA, Dominion,
EEI, and WECC explain that relays set according to sub-requirement R1.2
will not trip until loading exceeds 115 percent of the 15-minute
rating, which will always be higher than the 30-minute rating. EEI and
Ameren acknowledge that using 115 percent of the highest seasonal 15-
minute rating creates more conservative relay load limits, but point
out that this does not limit the operator's response time to 15
minutes.
184. TAPS and Dominion contend that the time periods identified in
sub-requirement R1.2 and TOP-004-1 refer to two distinct operating
situations. TAPS and Dominion state that the 15-minute rating
referenced in sub-requirement R1.2 refers to the time to respond to a
contingency in a known state (i.e., within the emergency rating), while
the 30-minute period in TOP-004-1 refers to the time to respond to an
unknown state (i.e., in a situation where the operating limits are
unknown, typically a state that has not been studied in stability
studies to identify stability limits).
185. Duke, EEI, and the PSEG Companies challenge what they perceive
to be the Commission's assumption that sub-requirement R1.2 is for
overload protection. They state that overcurrent relays are designed
and applied for fault protection and not for overload protection. EEI
adds that the Commission should recognize that sub-requirement R1.11 is
the requirement addressing overload protection. The PSEG Companies
assert that it is widely recognized by industry that the purpose of
PRC-023-1 is to ensure that lines refrain from tripping for maximum
loading conditions; once the maximum loading conditions are exceeded
the relays are free to operate for a fault.
c. Commission Determination
186. We decline to adopt the NOPR proposal to require the ERO to
revise sub-requirement R1.2 to mirror Reliability Standard TOP-004-1.
However, we will adopt the NOPR proposal to direct the ERO to modify
PRC-023-1 to require that transmission owners, generator owners, and
distribution providers give their transmission operators a list of
transmission facilities that implement sub-requirement R1.2. We agree
with Oncor that this is a simple approach to addressing the potential
for confusion identified by the Commission in the NOPR. Consistent with
Order No. 693, we do not prescribe this specific change as an exclusive
solution to our concerns regarding sub-requirement R1.2. As the
Commission stated in Order No. 693, where, as here, ``the Final Rule
identifies a concern and offers a specific approach to address the
concern, we will consider an equivalent alternative approach provided
that the ERO demonstrates that the alternative will address the
Commission's underlying concern or goal as efficiently and effectively
as the Commission's proposal.'' \147\ As discussed in the NOPR, 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 they may have
less than 30 minutes because the relay settings applied to protect
certain transmission facilities may have been set to operate applying a
15-minute rating in accordance with sub-requirement R1.2.
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\147\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 186.
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187. Contrary to some commenters' assertions, the Commission has
not misunderstood the purpose of the 15-minute rating and the relay set
points in sub-requirement R1.2. We realize that the 15-minute and 4-
hour ratings are the times that the entity's rating methodology has
determined that a facility can safely be loaded at that level and does
not correlate to the operating time of the protective relay. We also
realize that the protective relays on these facilities should not
operate until loading on the facility exceeds the protective relay
settings, including impedance or current settings and time delays.
Moreover, we understand that sub-requirement R1.2 is not for overload
protection, and we agree that entities that use the 15-minute rating
are expected to be capable of operating within this constraint. Our
goal with directing a modification to sub-requirement R1.2 is simply to
ensure that the transmission operator has full knowledge of which
facilities are applying a 15-minute rating instead of a 4-hour rating
so that the transmission
[[Page 16939]]
operator can factor this information into any necessary emergency
actions.
188. We also agree with TAPS and Dominion that the 15 minutes
referred to in sub-requirement R1.2 is for operating to a known 15-
minute limit and therefore serves a purpose different from the 30
minutes allowed in TOP-004-1 for operators in an unknown operating
state that must return to a known operating state. However, once the
relay settings of a facility that implements sub-requirement R1.2 go
above 115 percent of the facility's 15-minute rating, the facility may
trip and add to the outages that the transmission operator must
address. Simply put, the Commission is directing this modification so
that the requirement includes what Duke and others said they expect
would be necessary for the operator to have sufficient information to
reliably operate the system--knowledge of which facilities implement
PRC-023-1 criteria applying a 15-minute rating so that the operator can
utilize the system for the 15 minutes that the rating allows.
Therefore, the Commission agrees that, while the time periods
identified in PRC-023-1 and TOP-004-1 are for different purposes, the
operator's response time for both and the consequences of inaction are
effectively the same.
189. Mandatory Reliability Standards should be clear and
unambiguous regarding what is required and who is required to
comply.\148\ This is not the case with sub-requirement R1.2. For
example, the ERO states in its comments that entities that implement
sub-requirement R1.2 commit to operate to the 15-minute rating and to
respond to rating violations within the 15 minutes.\149\ While we agree
with the ERO, EEI and Ameren do not interpret sub-requirement R1.2 to
limit the operator's response time to 15 minutes. Because there are
different understandings with regard to the implementation of sub-
requirement R1.2, we adopt the NOPR proposal and direct the ERO to
develop a new requirement that transmission owners, generator owners,
and distribution providers give their transmission operators a list of
transmission facilities that implement sub-requirement R1.2.
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\148\ Order No. 672, FERC Stats. & Regs. ] 31,204 at P 325.
\149\ NERC Comments at 28.
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3. Sub-Requirement R1.10
190. Sub-requirement R1.10 provides criteria for transformer fault
relays and transmission line relays on transmission lines that
terminate in a transformer. It requires that relays be set so that the
transformer fault 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.
a. NOPR Proposal
191. In the NOPR, the Commission expressed concern that overloading
facilities at any time, but especially during system faults, could
lower reliability and present a safety concern. The Commission
explained that 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. The
Commission stated that, for this topology, protective relay settings
implemented according to sub-requirement R1.10 would allow the
transformer to be subjected to overloads higher than its established
ratings for unspecified periods of time. The Commission stated that
this negatively impacts reliability and raises safety concerns because
transformers that have been subjected to currents over their maximum
rating have been recorded as failing violently, resulting in
substantial fires. The Commission acknowledged that safety
considerations are outside of its jurisdiction, but asserted that
requirements in a Reliability Standard should not be interpreted as
requiring unsafe actions or designs. The Commission proposed,
therefore, to direct the ERO to submit a modification that requires any
entity that implements sub-requirement R1.10 to either 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 or alter its protection system or
topology.
b. Comments
192. NERC states that the primary source of technical information
for sub-requirement R1.10 is IEEE Standard C37.91-2008, IEEE Guide for
Protecting Power Transformers (specifically, sections 8.6 and 8.6.1 and
Appendix A).\150\ NERC explains that phase overcurrent devices must
coordinate with duration curves, and that minimum current stated on the
curves must equal two times transformer base current. NERC argues that
PRC-023-1 is consistent with IEEE Standard C37.91-2008 and IEEE
Standard C57.109-1993 (which is referenced in Appendix A of IEEE
Standard C37.91-2008) because it requires entities that use overcurrent
relays to consider loadability (a non-fault induced transformer
loading), and because a setting of 150 percent of the transformer
nameplate rating or 115 percent of the highest operator-established
emergency rating will always be less than 200 percent of the
transformer forced-cooled nameplate rating.\151\
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\150\ NERC explains that sections 8.6 and 8.6.1 of the Guide
address the settings of transformer phase overcurrent protection,
and Appendix A contains through-fault duration curves for various
size power transformers that provide fault current durations as
plotted against transformer base current. Section 8.6 states:
8.6. Protection of a transformer against damage due to the
failure to clear an external fault should always be carefully
considered. This damage usually manifests itself as internal,
thermal, or mechanical damage caused by fault current flowing
through the transformer. The curves in Annex A show through-fault-
current duration curves to limit damage to the transformer. Through-
faults that can cause damage to the transformer include restricted
faults or those some distance away from the station. The fault
current, in terms of the transformer rating, tends to be low
(approximately 0.5 to 5.0 times transformer rating) and the bus
voltage tends to remain at relatively high values. The fault current
will be superimposed on load current, compounding the thermal load
on the transformer. Several factors will influence the decision as
to how much and what kind of backup is required for the transformer
under consideration. Significant factors are the operating
experience with regard to clearing remote faults, the cost
effectiveness to provide this coverage considering the size and
location of the transformer, and the general protection philosophies
used by the utility.
Section 8.6.1 states
8.6.1. When overcurrent relays are used for transformer backup,
their sensitivity is limited because they should be set above
maximum load current. Separate ground relays may be applied with the
phase relays to provide better sensitivity for some ground faults.
Usual considerations for setting overcurrent relays are described in
8.3. When overcurrent relays are applied to the high-voltage side of
transformers with three or more windings, they should have pickup
values that will permit the transformer to carry its rated load plus
margin for overload. * * * When two or more transformers are
operated in parallel to share a common load, the overcurrent relay
settings should consider the short-time overloads on one transformer
upon loss of the other transformer. Relays on individual
transformers may require pickup levels greater than twice the forced
cooled rating of the transformer to avoid tripping.
\151\ NERC Comments at 30.
---------------------------------------------------------------------------
193. TAPS describes the Commission's assertion that a ``Reliability
Standard should not be interpreted as requiring unsafe actions or
designs'' as a ``jurisdictional bootstrap'' that nevertheless fails to
remove questions about the Commission's authority to require a
modification that addresses safety concerns. TAPS explains that section
215(i)(2) of the FPA provides that states retain jurisdiction over
safety concerns,
[[Page 16940]]
a point that the Commission acknowledged in the NOPR.
194. Several commenters point out that protective relays are
designed to protect the system from faults, not overloads.\152\ Ameren,
EEI, and Duke observe that other protection methods, such as
temperature monitors, are typically employed for thermal protection.
WECC observes that sub-requirement R1.11 addresses overload protection.
EEI adds that there is no loadability issue if a remote breaker can
provide adequate protection and the asset owner can still comply with
PRC-023-1.
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\152\ See, e.g., Ameren, BPA, Duke, EEI, Exelon, NERC, and WECC.
---------------------------------------------------------------------------
195. Consumers Energy, EEI, and NERC argue that the mitigation of
thermal overloads is best left to operator response, not to automatic
devices, so that the operator may take well-reasoned action that best
supports the Reliable Operation of the bulk electric system while
addressing the overload. Consumers Energy argues that any entity that
wishes to establish automatic actions for overload conditions should
apply devices designed specifically for that purpose, with response
times appropriate for overload, or should develop and install a special
protection system in accordance PRC-012-0 to detect and take actions to
relieve the overload. EEI maintains that any transformer requiring
overload protection should have it specifically applied regardless of
transmission line protection, or system configuration. Ameren and EEI
contend that providing adequate transformer protection is in the best
interest of the asset owner. The PSEG Companies argue that the
Commission's proposal is beyond the scope of PRC-023-1 because it is
responsibility of the protection system designer to employ good
engineering practice to ensure protection for faulted systems.
Similarly, the PSEG Companies argue that system operations groups are
responsible for ensuring that equipment is properly protected and
loaded within limits.
196. NERC states that overcurrent relays are typically used only
for backup detection of through-faults outside of the primary
protective zone. NERC maintains that a transformer subjected to a
through-fault for an extended period of time may compromise its design,
but that if an entity wishes to provide overload protection for its
transformer, such protection should be provided by devices designed for
that purpose and have response times appropriate for overload
protection (e.g., several seconds and longer). BPA makes the similar
claim that the overload current capability required by PRC-023-1 for
transformers is not a safety concern for moderate time durations. BPA
explains that these setting levels (or higher) have been common in the
industry to prevent relay operation on load. BPA acknowledges that,
over prolonged periods, these overload currents could cause overheating
which could reduce the life of the transformer. BPA states, however,
that protective relays are not intended to protect for these currents
because ample time is available for system operators to make system
changes to mitigate the transformer overload in a controlled manner,
which is preferable to automatic relay operation. BPA adds that there
are other protective relays to protect the transformer from internal
faults or large through-currents due to faults outside of the
transformer.
197. Several commenters argue that the Commission's proposal is
unnecessary. EEI argues that the Commission's proposal is unnecessary
because zone 2 time-delayed relays are typically set to operate in less
than one second, while IEEE Standard C57.109-1993 establishes the
thermal damage curve for transformers above 30 MVA and allows 25 times
rated transformer current for two seconds. EEI also states that all
transformers have an overload capability that has been covered by
system dispatcher action regardless of its connection method. EEI
points out that sub-requirement R1.10 requires load responsive
transformer relays to be set to carry at least 150 percent of the
transformer nameplate rating, and that system dispatcher response time
is based on the degree of overload, not the connection method. EEI
states that sub-requirement R1.10 allows conservative line protection,
which improves the setting at which relays can be set to sense fault
conditions. Duke adds that facility ratings, including transformer
facility ratings, are established and communicated to reliability
coordinators, planning authorities, transmission planners, and
transmission operators in accordance with FAC-009-1, Requirements R1
and R2, and that each transmission operator is trained to operate the
system within the ratings that are established and communicated to it
pursuant to FAC-009-1.
198. Exelon claims that the Commission's description of sub-
requirement R1.10 is inaccurate. Exelon maintains that sub-requirement
R1.10 will not allow transformers to be subjected to overloads higher
than their ratings for unspecified periods. Exelon claims that sub-
requirement R1.10 addresses fault protection for lines terminated with
a transformer--not transformer loading. Exelon states that the
protection systems that protect against faults are different from the
protection systems that protect against overloads.
199. Exelon claims, moreover, that the Commission's proposed
modification is imprecise. Exelon explains that the term ``the longest
clearing time associated with the fault from the facility owner''
leaves open the question of what assumptions should be used. For
example, Exelon states that it is unclear whether the time period to be
measured is based on normal backup clearing time or some other
interval. Exelon contends that without such precision, compliance with
any modified requirement will be impossible.
200. Basin agrees that the Commission has a valid concern when it
comes to establishing overload limits without regard to whether the
limiting piece of equipment is capable of sustaining the overload for
the longest clearing time associated with the fault. Basin argues,
however, that the Commission's mixture of terminologies in the NOPR
(e.g., thermal ratings, fault current, load current and faults) is
misleading in terms of cause and effect and risk management. Basin
requests, therefore, that the Commission direct NERC to make the change
using language that is clear and consistent.
201. Basin argues, however, that the Commission should not impose
any additional requirements on lines terminating in transformers. Basin
explains that while this equipment is susceptible to damage from
overloads, other equipment also is subject to overload-related damage
and the Commission should not address this issue on a piecemeal basis.
Basin contends that the safety issue related to lines terminating in
transformers merits unique consideration and is outside the scope of
this proceeding. Basin argues, therefore, that the Commission should
not direct any specific actions with respect to such equipment in this
docket.
202. Tri-State agrees with the Commission that it is prudent to
ensure that relays operate before the appropriate transformer damage
curve is intersected. Tri-State adds that it finds little difference in
the proposed allowable current sensing settings used in sub-
requirements R1.10 and R1.11 except for the use of the term ``fault
protection'' in sub-requirement R1.10 and ``overload protection'' in
sub-requirement R1.11.
[[Page 16941]]
c. Commission Determination
203. We adopt the NOPR proposal and direct the ERO to modify sub-
requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated
overload for the longest clearing time associated with the fault.\153\
As with our other directives in this Final Rule, we do not prescribe
this specific change as an exclusive solution to our reliability
concerns regarding sub-requirement R1.10. As we have stated, the ERO
can propose an alternative solution that it believes is an equally
effective and efficient approach to addressing the Commission's concern
that entities respect facility limits when implementing sub-requirement
R1.10.
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\153\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 186.
---------------------------------------------------------------------------
204. At the outset, we acknowledge that section 215 of the FPA does
not authorize the Commission to set and enforce compliance with
standards for the safety of electric facilities or services.\154\ While
the NOPR identified a potential safety issue with sub-requirement
R1.10, we clarify that we do not rest our decision to adopt the NOPR
proposal on safety concerns and reject TAPS's contrary assertion.
---------------------------------------------------------------------------
\154\ 16 U.S.C. 824o(i)(2).
---------------------------------------------------------------------------
205. We also clarify that the Commission's use of the term
``overload'' in the NOPR refers to the combination of load and fault
current external to the transformer zone of protection (through-
current) that can flow through the transformer. These overload currents
can be higher than the transformer's established ratings, subjecting
the transformer to possible thermal damage. As discussed in the NOPR,
and as NERC and Basin confirm, subjecting transformers to overloads
over their maximum rating compromises their design and subjects the
transformer to overload-related damage. Thus, we reject Exelon's
assertion that sub-requirement R1.10 will not allow transformers to be
subjected to through-currents that would overload the transformer.
206. Since sub-requirement R1.10 applies to the topology where
there is no breaker installed on the high-voltage side of the
transformer, faults within the transformer or at the low-voltage side
of the transformer are cleared by tripping the remote breaker on the
transmission line and the transformer low-voltage breaker. Because
faults on the low-voltage side of the transformer will generally be
lower in magnitude as measured at the remote breaker due to the large
impedance of the transformer, fault protection relays set at 150
percent of the transformer nameplate rating or 115 percent of the
highest operator established emergency transformer rating may be set
too high to operate for faults on the low-voltage side of the
transformer. Consequently, delayed clearing of faults (i.e., the
longest clearing time associated with the faults) from the high-voltage
side of the transformer may occur and subject the transformer to
overloads, i.e., through-currents higher than the transformer's rating.
Overcurrent relays used for transformer protection have a limited
ability to detect these types of faults because they are set above the
maximum load current \155\ for entities that set these relays following
the IEEE Standards. It is for this reason that the ability of the
transformer to sustain overloads, i.e., through-currents, for the
longest clearing time associated with the fault must be verified.
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\155\ Section 8.6.1 of IEEE Standard C37.91-2008 states that
``[w]hen overcurrent relays are used for transformer backup, their
sensitivity is limited because they should be set above maximum load
current.''
---------------------------------------------------------------------------
207. NERC and others state that sub-requirement R1.10 is consistent
with IEEE Standards C37.91-2008 and C57.109-1993. While the Commission
has approved Reliability Standards that reference other industry
standards,\156\ Reliability Standard PRC-023-1 does not reference
either IEEE Standard. Thus, neither IEEE Standard is mandatory and
enforceable under section 215 of the FPA.
---------------------------------------------------------------------------
\156\ E.g., Reliability Standard FAC-003-1, Transmission
Vegetation Management Program, Footnote 1 (reference to ANSI A300,
Tree Care Operations).
---------------------------------------------------------------------------
208. Moreover, we have several concerns about relying on the IEEE
Standards to address the reliability issue we have identified. First,
an entity could provide a facility rating that was just within the
voluntary requirements in the IEEE Standards, however, when setting
protection relays according to sub-requirement R1.10, the transformer
could be subject to currents above its capability as previously
described. Second, the IEEE Standards may not apply to transformers
manufactured before 1993 because the guidelines established in C57.109-
1993 do not apply to transformers manufactured before 1993.
209. We are not persuaded by the ERO's statement that ``a setting
of 150 percent of the transformer nameplate rating or 115 percent of
the highest operator established emergency rating will always be less
than 200 percent of the transformer forced-cooled nameplate rating.''
Referring to section 8.6.1 of IEEE Standard C37.91, we point out that
this statement applies only to the specific configuration where ``two
or more transformers are operated in parallel to share a common load,''
which may not be the configuration for every transformer on the Bulk-
Power System. We also note that section 8.6.1 further states that
``[r]elays on individual transformers may require pickup levels greater
than twice the force cooled rating of the transformer to avoid
tripping.'' Since Requirement R1.10 applies to any topology, it must be
robust enough to address the reliability issues of any topology.
Section 8.6.1 of IEEE Standard C37.91 applies only to two or more
transformers that are operated in parallel. Consequently, we reject
NERC's assertion that it is not possible to exceed the rating of a
single transformer.
210. Adopting the NOPR proposal to require entities that implement
sub-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 would address the Commission's
reliability concerns. Applying protection systems that do not respect
the actual or verified capability of the limiting facility will result
in a degradation of system reliability. In this instance, applying sub-
requirement R1.10 without regard to the topology and capability of each
transformer could cause the transformer to fail. Failure of the
transformer may not be limited to only the affected transformer, but
may also affect other Bulk-Power Systems elements in its vicinity,
further degrading the reliability of the Bulk-Power System.
211. While NERC explains that sub-requirement R1.10 is intended for
specific transformer fault protection relays that are set to protect
for fault conditions and not excessive load conditions, sub-requirement
R1.10 does not identify that intent.\157\ Additionally, sub-requirement
R1.11 of PRC-023-1 establishes criteria for transformer overload
protection relays that do not comply with sub-requirement R1.10.
Because sub-requirement R1.11 establishes that the protection must
allow an overload for 15 minutes, we disagree with WECC that sub-
requirement R1.11 addresses the Commission's reliability concern with
overloads.
---------------------------------------------------------------------------
\157\ NERC Petition at 11.
---------------------------------------------------------------------------
212. We acknowledge that relays can be set to protect for faults as
well as overloads and that the operation of relays for fault conditions
is much faster than for overload conditions. This is because faults
need to be removed
[[Page 16942]]
quickly from the Bulk-Power System to limit the severity and spread of
system disturbances and prevent possible damage to protected elements,
while overload relays are designed to operate more slowly, and when
applicable, allow time for operators to implement operator control
actions to mitigate the overloaded facility. Nevertheless, both fault
and overload relays are load-responsive relays. Thus, we agree with
those commenters that state that manual mitigation of thermal overloads
is best left to system operators, who can take appropriate actions to
support Reliable Operation of the Bulk-Power System. Moreover, because
both types of relays are load-responsive relays, we disagree with PSEG
that the Commission's proposal is beyond the scope of PRC-023-1.
4. Sub-Requirement R1.12
213. Sub-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. In its petition, NERC stated that if
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.\158\ NERC also stated that PRC-023-1 should cause
no undue negative effect on competition or restrict the grid beyond
what is necessary for reliability.\159\
---------------------------------------------------------------------------
\158\ Id. at 14.
\159\ Id. at 27.
---------------------------------------------------------------------------
a. NOPR Proposal
214. In the NOPR, the Commission expressed concern that sub-
requirement R1.12 allows entities to technically comply with the
Reliability Standard without achieving its stated purpose. The
Commission explained that because entities can set their relays to
limit the load carrying capability of a transmission line, any line
with relays set according to sub-requirement R1.12 will not be utilized
to its full potential in response to sudden increases in line loadings
or power swings. The Commission stated this will make the natural
response of the Bulk-Power System less robust in the case of system
disturbances. The Commission added that an entity that uses a
protection system that requires it to set its relays pursuant to sub-
requirement R1.12 may not be able to satisfy its reliability
obligations. Consequently, the Commission requested comments on whether
the use of such a protection system is consistent with the Reliability
Standard's objectives, and whether it should direct a modification that
would require entities that employ such a protection system to use a
different system.
b. Comments
215. NERC opposes the Commission's proposal and disagrees with the
Commission's assertion that sub-requirement R1.12 allows entities to
comply with the Reliability Standard without achieving its purpose.
NERC states that the Reliability Standard's objectives include ensuring
reliable detection of all network faults and preventing undesired
protective relay operation that interferes with the system operator's
ability to take remedial action. NERC explains that use of sub-
requirement R1.12 is restricted to cases where adequate line protection
cannot be achieved without restricting the loadability of the protected
transmission element.
216. NERC and Consumers Energy argue that sub-requirement R1.12
could have helped mitigate the August 2003 blackout. NERC and Consumers
Energy explain that many of the lines that tripped during the blackout
were below their emergency rating and tripped because of loading
limitations imposed by relay settings. NERC and Consumers Energy state
that these lines tripped without warning to system operators, who were
unaware of loading limitations imposed by relay settings. NERC and
Consumers Energy note that sub-requirement R1.12 mandates that facility
ratings reflect relay loadability limitations and speculate that, if
this had been the case on the day of the blackout, system operators
would have known that they were approaching the relay loadability
limitation and could have taken mitigating action.\160\
---------------------------------------------------------------------------
\160\ Consumers Energy at 12-13; NERC Comments at 32.
---------------------------------------------------------------------------
217. Other commenters share NERC's view that sub-requirement R1.12
is consistent with the Reliability Standard's purpose.\161\ Ameren
argues that sub-requirement R1.12 appropriately recognizes that
priority must be given to fault detection over loadability because
undetected faults can result in generation and load instability,
outages, and increased damage and repair time. Basin states that while
sub-requirement R1.12 may lead to relay settings that limit a line's
full potential in response to sudden increases in line loadings or
power swings, it maximizes loadability to the extent possible without
compromising the primary zone of protection.
---------------------------------------------------------------------------
\161\ See also Ameren, Basin, EEI, McDonald, and WECC.
---------------------------------------------------------------------------
218. Commenters also claim that sub-requirement R1.12 is intended
to provide acceptable protection for uncommon configurations.\162\ EEI,
WECC, and Consumers Energy speculate that sub-requirement R1.12 will
most commonly apply to lines with three or more terminals, which
usually require larger zone 2 settings than two-terminal lines.
Consumers Energy states that such configurations are actually selected
for reliability, not cost, such that removal of a line will
simultaneously remove other components that could not be reliably
served in the absence of that line. Oncor states that the purpose of
sub-requirement R1.12 is to handle those less common system
configurations where operating the system at the maximum capacity of
the equipment in the configuration is within the operating range of the
protective relay settings to detect and clear all faults in the
protected configuration.
---------------------------------------------------------------------------
\162\ See, e.g., Consumers Energy, EEI, and Oncor.
---------------------------------------------------------------------------
219. Some commenters argue that utilities should have the
flexibility to decide what is necessary for their systems. For example,
South Carolina E&G maintains that utilities should be allowed to either
restrict line loadability for protection or use a different protection
system appropriate for the particular situation. TVA argues that a
utility should be able to establish facility ratings based on thermal
or relay limits, and that as long as facility ratings are applied in
system studies correctly (and such studies show no violations), a
utility should not be required to change its protective schemes to
allow a higher facility rating based on thermal limits.
220. TAPS describes sub-requirement R1.12 as an example of NERC and
industry experts properly exercising flexibility to balance a number of
reliability factors, including cost, as the Commission recognized is
appropriate in Order No. 672. TAPS reiterates that in Order No. 672 the
Commission stated that a proposed Reliability Standard need not reflect
the optimal method, or ``best practice,'' for achieving its reliability
goal without regard to implementation cost or historical regional
infrastructure design.\163\ TAPS argues that in assessing whether the
Reliability Standard achieves its reliability goal efficiently and
effectively, the Commission should give
[[Page 16943]]
due weight to NERC's balancing of competing factors. TAPS also claims
that the Commission's proposal to require a broad change of equipment
is expensive and ``run[s] afoul'' of sections 215(a)(3) \164\ and
(i)(2) of the FPA, which limit Reliability Standards that require
expansion of facilities.
---------------------------------------------------------------------------
\163\ TAPS at 26 (citing Order No. 672, FERC Stats. & Regs. ]
31,204 at P 328).
\164\ 16 U.S.C. 824o(a)(3).
---------------------------------------------------------------------------
221. APPA states that the Commission's proposal appears to require
NERC to prohibit protection systems that would require the use of sub-
requirement R1.12, effectively writing sub-requirement R1.12 out of the
Reliability Standard. APPA argues that the Commission is proposing to
direct NERC to adopt a specific modification that may not be the best
or most efficient way to address the Commission's concerns. APPA states
that it agrees with the Commission raising the issue to the extent that
the Commission is concerned about the adverse impact of sub-requirement
R1.12 on Available Transfer Capability. APPA contends, however, that
having raised the issue, the Commission should direct NERC as the ERO
to develop solutions rather than dictate a solution in the first
instance.
222. The PSEG Companies argue that it is impractical to require
entities to replace existing impedance relay systems without evidence
that their continued use will have a negative reliability impact. The
PSEG Companies contend that protection systems should be replaced only
if reliability studies show that the limits imposed on the system by
the use of sub-requirement R1.12 will truly impede reliability. Oncor
argues that a modification that would require entities that employ
impedance relays to replace them with a current differential or pilot
wire relay system that is immune to load or stable power swings would
eliminate the valuable backup feature of the impedance relay and
actually reduce the reliability of the grid serving the atypical
configuration.
223. EEI and WECC assert that sub-requirement R1.12 can reasonably
be interpreted as the first step in implementing the Commission's
proposal to limit the reach of zone 3/zone 2 relays.\165\ EEI and WECC
explain that sub-requirement R1.12 imposes a maximum reach for distance
relays of 125 percent of the apparent length of the protected line,
which allows relays to dependably detect faults. EEI and WECC add that
use of sub-requirement R1.12 may prevent entities from using time-
delayed, over reaching zone 3 relays as remote backup protection,
unless they employ other load limiting relay features. EEI and WECC
argue that even with this single possible limitation, this loadability
method is consistent with the Reliability Standard's objectives.
---------------------------------------------------------------------------
\165\ EEI at 25; WECC at 5-6.
---------------------------------------------------------------------------
c. Commission Determination
224. We decline to adopt the NOPR proposal. After further
consideration, we think that it is incumbent on entities that implement
sub-requirement R1.12 to ensure that they implement it in a manner that
is consistent and coordinated with the Requirements of existing
Reliability Standards and that achieves performance results consistent
with their obligations under existing Standards. While we are not
adopting the NOPR proposal, we direct the ERO to document, subject to
audit by the Commission, and to make available for review to users,
owners and operators of the Bulk-Power System, by request, a list of
those facilities that have protective relays set pursuant to sub-
requirement R1.12. We believe that this transparency will allow users,
owners, and operators of the Bulk-Power System to know which facilities
have protective relay settings, implementing R1.12, that limit the
facility's capability.
225. We also disagree with commenters who argue that the few
instances where a protection system implements sub-requirement R1.12
are not a threat to the reliability of the Bulk-Power System unless
they have been declared critical circuits. Protective relays on Bulk-
Power Systems elements are an integral part of Reliable Operation.\166\
Any instance of a protection system that does not ensure Reliable
Operation is a reliability concern, not only to prevent and limit the
severity and spread of disturbances, but also to prevent possible
damage to protected elements.\167\
---------------------------------------------------------------------------
\166\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1435.
\167\ Id.
---------------------------------------------------------------------------
226. We also disagree with EEI's and WECC's assertion that sub-
requirement R1.12 can reasonably be interpreted as the first step in
implementing the Commission's proposal to limit the reach of zone 3/
zone 2 relays.\168\ Sub-requirement R1.12 establishes loadability
criteria for distance relays when the desired transmission line
capability is limited by the requirement to protect the transmission
line, and not explicitly for the application of zone 3/zone 2 distance
relays applied as remote circuit breaker failure and backup protection.
As discussed previously, the Commission proposed to establish a maximum
allowable reach for such relays because that their large reaches make
the relays susceptible to tripping from load.
---------------------------------------------------------------------------
\168\ As discussed previously, the Commission has decided not to
adopt the NOPR proposal for establishing a maximum allowable reach
for the application of zone 3/zone 2 relays applied as remote
circuit breaker failure and backup protection upon consideration of
comments.
---------------------------------------------------------------------------
G. Requirement R2
227. Requirement R2 states that entities that use a circuit with
the protective relay 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.
The entities also must obtain the agreement of the planning
coordinator, transmission operator, and reliability coordinator as to
the calculated circuit capability. The Commission did not make any
proposal regarding Requirement R2.
1. Comments
228. ERCOT and IRC state that the Commission should clarify that
the ``agreement'' contemplated in Requirement R2 only means that the
entity calculating the circuit capability is required to provide the
circuit capability to the relevant functional entities. ERCOT notes
that because it is the planning coordinator, transmission operator and
reliability coordinator in the ERCOT region, it would be responsible
for reviewing and approving the calculated circuit capabilities under
Requirement R2. ERCOT states that it lacks the necessary analysis tools
and data (e.g., conductor sag software and transmission design data to
determine emergency ratings) to provide an informed opinion on the
circuit capabilities calculated by transmission owners, generator
owners, or distribution owners pursuant to Requirement R2. ERCOT argues
that the entities that own the facilities are in the best position to
establish those limits, and that planning coordinators, transmission
operators, and reliability coordinators should not be required to
approve them. ERCOT contends that planning coordinators, transmission
operators, and reliability coordinators should merely be made aware of
the limits in order to respect them while executing their duties. IRC
makes the similar claim that the term ``agreement'' in Requirement R2
requires only a data check or confirmation, such that planning
coordinators, transmission operators, and reliability coordinators must
simply agree that they will use the circuit capability provided by the
transmission owner, generator owner, or distribution owner. IRC argues
that this interpretation is consistent with both
[[Page 16944]]
FAC-008-1, which requires transmission and generator owners to
establish facility rating methodologies for their facilities and
provide them to reliability coordinators, transmission operators,
transmission planners, and planning authorities, and FAC-009-0, which
requires transmission and generator owners to provide the resultant
facility ratings to the same entities.
2. Commission Determination
229. We do not agree with ERCOT and IRC that an entity's obligation
to obtain the ``agreement'' of the planning coordinator, transmission
operator, or reliability coordinator with the calculated circuit
capability only means that the entity calculating the circuit
capability is required to provide the circuit capability to the
relevant functional entities. We interpret the language ``shall obtain
the agreement'' in Requirement R2 to require that the entity
calculating the circuit capability must reach an understanding with the
relevant functional entity that the calculated circuit capability is
capable of achieving the reliability goal of PRC-023-1. Since PRC-023-1
is intended to ensure that protective relay settings do not limit
transmission loadability or interfere with system operators' ability to
take remedial action to protect system reliability, and to ensure that
relays reliably detect all fault conditions and protect the electrical
network from these faults, we expect the agreement to center around
achieving these purposes.
H. Requirement R3 and Its Sub-Requirements
230. Requirement R3 directs planning coordinators to identify which
sub-200 kV facilities are critical to the reliability of the bulk
electric system and therefore subject to Requirement R1.\169\ Sub-
requirement R3.1 directs planning coordinators to have a process to
identify critical facilities. Sub-requirement R3.1.1 specifies that the
process must consider input from adjoining planning coordinators and
affected reliability coordinators. Sub-requirements R3.2 and R3.3
direct planning coordinators to maintain a list of critical facilities
and provide it to reliability coordinators, transmission owners,
generator owners, and distribution providers within 30 days of
establishing it, and within 30 days of making any change to it.
---------------------------------------------------------------------------
\169\ As proposed by NERC, Requirement R3 directs planning
coordinators to identify the 100 kV-200 kV facilities that should be
subject to Requirement R1. As we have explained, in this Final Rule
we direct that the ERO revise Requirement R3 so that planning
coordinators also identify sub-100 kV facilities that should be
subject to the Reliability Standard.
---------------------------------------------------------------------------
1. Role of the Planning Coordinator
a. Comments
231. ERCOT argues that the Commission should follow the example of
the Critical Infrastructure Protection (CIP) Reliability Standards and
direct the ERO to make facility owners, rather than planning
coordinators, responsible for identifying critical sub-200 kV
facilities and for maintaining and distributing the critical facilities
list. ERCOT contends that while planning coordinators and other
functional entities must receive all relevant information about
facilities in their region, facility owners have the right and
obligation to make criticality determinations about their facilities.
ERCOT argues that the CIP Reliability Standards support its position,
as they require facility owners to identify critical assets.
232. ERCOT also requests confirmation that sub-requirement R3.1.1
does not apply to the ERCOT region because it is not synchronously
interconnected with any other control area and because ERCOT is the
only planning coordinator and reliability coordinator within the
region.
b. Commission Determination
233. We disagree with ERCOT and will not direct the ERO to make
facility owners responsible for identifying critical sub-200 kV
facilities or for maintaining and distributing the critical facilities
list. We also reject ERCOT's comparison between PRC-023-1 and the CIP
Reliability Standards. Facility owners are responsible for maintaining
only their own facilities. Planning coordinators, on the other hand,
are charged with assessing the long-term reliability of their planning
authority areas.\170\ Consequently, planning coordinators are better
prepared and equipped to make the comprehensive criticality
determinations for their areas for the purposes of PRC-023-1. We thus
agree with the ERO that planning coordinators are better suited to make
the criticality determinations for the purposes of PRC-023-1.
---------------------------------------------------------------------------
\170\ See NERC Function Model, Version 3 at 14.
---------------------------------------------------------------------------
234. Finally, while we acknowledge that ERCOT is not synchronously
interconnected with any other control area and that it is the only
planning coordinator and reliability coordinator in its region, we
clarify that any request for a regional exemption from PRC-023-1 is an
applicability matter that must be raised in the Reliability Standards
development process and included in a modified Reliability
Standard.\171\ Consequently, Requirement R3 and its sub-requirements
apply to ERCOT.
---------------------------------------------------------------------------
\171\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1125.
---------------------------------------------------------------------------
2. Sub-Requirement R3.3
a. NOPR Proposal
235. The Commission proposed to direct the ERO to add Regional
Entities to the list of entities that receive the critical facilities
list pursuant to sub-requirement R3.3.
b. Comments
236. NERC and WECC agree with the Commission that the Regional
Entity should receive the critical facilities list. EEI acknowledges
that the Commission's proposal may have merit, but opposes a
modification. EEI explains that the Regional Entity can already request
the data from planning authorities and reliability coordinators at any
time, and argues that it is not necessary to formalize the process.
c. Commission Determination
237. We adopt the NOPR proposal and direct the ERO to modify the
Reliability Standard to add the Regional Entity to the list of entities
that receive the critical facilities list. The Regional Entity must
know which facilities in its area have been identified as operationally
significant and could contribute to cascading outages and the loss of
load. Additionally, providing Regional Entities with the critical
facilities list will aid in the overall coordination of planning and
operational studies among planning coordinators, transmission owners,
generator owners, distribution providers, and Regional Entities. As
with our other directives in this Final Rule, we do not prescribe this
specific change as an exclusive solution to our reliability concerns
regarding sub-requirement R3.3. As we have stated, the ERO can propose
an alternative solution that it believes is an equally effective and
efficient approach to addressing the Commission's reliability
concerns.\172\
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\172\ Id. P 186.
---------------------------------------------------------------------------
I. Attachment A
238. Attachment A of the Reliability Standard contains three
sections: (1) A non-exhaustive list of load-responsive relays subject
to the Standard; (2) a statement that out-of-step blocking protective
schemes are subject to the Standard and shall be evaluated to ensure
that they do not block trip for fault during the loading conditions
defined within the Standard's
[[Page 16945]]
requirements; and (3) a list of protective systems that are expressly
excluded from the Standard's requirements. In the NOPR, the Commission
expressed concerns about sections 2 and 3.
1. Section 2: Evaluation of Out-of-Step Blocking Schemes
239. Section 2 of Attachment A states that the ``[Reliability
Standard] includes out-of-step blocking schemes which shall be
evaluated to ensure that they do not block trip for faults during the
loading conditions defined within the requirements.''
a. NOPR Proposal
240. In the NOPR, the Commission stated that since the ERO intends
to require the evaluation of out-of-step blocking applications,
language to this effect should be included in PRC-023-1 as a
Requirement. To this end, the Commission proposed to direct the ERO to
add section 2 of Attachment A to PRC-023-1 as an additional Requirement
with the appropriate violation risk factor and violation severity level
assignments.
b. Comments
241. NERC agrees that the proposed modification is appropriate and
proposes to implement it through the full Reliability Standards
development process in the next modification of PRC-023-1. In the
meantime, NERC requests that the Commission approve Attachment A as
currently written.\173\
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\173\ See also Duke and IESO/Hydro One.
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242. WECC asserts that the Commission's proposal is reasonable
because the obligation to evaluate out-of-step blocking schemes is part
of PRC-023-1, but carries no penalty without a violation risk factor
and violation severity level. WECC suggests that the Commission take
the same approach with respect to out-of-step tripping (section 1.2).
WECC explains that without appropriate load supervision, out-of-step
tripping may subject circuit breakers to excessive over-voltages, if it
occurs at all.
243. Dominion, EEI, and Oncor disagree with the Commission's
proposal. Rather than make it a Requirement, Dominion argues that the
statement about out-of-step blocking schemes should be removed from
PRC-023-1 and included in a Reliability Standard that addresses stable
power swings. EEI asserts that section 2 appropriately appears in
Attachment A because Attachment A identifies the types of transmission
line relays and relay schemes that are subject to the Reliability
Standard, and out of step blocking relays are ``transmission line
relays'' addressed in Requirement R1. Oncor argues that section 2 is
already a requirement because it is in an attachment instead of an
appendix.
c. Commission Determination
244. We adopt the NOPR proposal and direct the ERO to include
section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and
violation severity level.
245. EEI correctly states that Attachment A is a compilation of the
types of transmission line relays and relay schemes that are subject to
PRC-023-1, and that section 2 specifies that out-of-step blocking
schemes are subject to it. However, section 2 also creates an
obligation to evaluate out-of-step blocking schemes to ensure that they
do not block trip for faults during the loading conditions defined
within the Reliability Standard's Requirements. This is an obligation
that is not stated in, or referenced by, any Requirement in the
Reliability Standard. Consequently, this obligation is not currently
associated with a violation risk factor or violation severity level.
246. Although the obligation to evaluate out-of-step blocking
schemes is currently not stated in a Requirement, it nevertheless
remains an obligation imposed on entities by PRC-023-1 because it is a
part of Attachment A and therefore a part of PRC-023-1. Consequently,
we clarify that entities must comply with this obligation while the ERO
modifies PRC-023-1 to include it as a Requirement.
247. We disagree with Dominion's suggestion that the Commission
direct the ERO to remove section 2 from PRC-023-1 and include it in a
Reliability Standard that addresses stable power swings. It is
appropriate to include section 2 as a Requirement in PRC-023-1 because
out-of-step blocking schemes must be allowed to trip for faults during
the loading conditions defined within PRC-023-1. Otherwise, faults that
occur during a power swing may result in system instability if not
cleared.
248. Finally, we will not direct the ERO to make section 1.2 into a
Requirement as WECC suggests. Section 1 of Attachment A is a non-
exhaustive list of relays and protection systems that are subject to
Attachment A; unlike section 2, section 1 does not create substantive
obligations that are neither stated in nor referenced by the
Requirements. Section 1.2 merely lists out-of-step tripping systems as
one of the systems that are subject to the Reliability Standard and
must be set pursuant to Requirement R1.
2. Section 3: Protection Systems Excluded From the Reliability Standard
249. Section 3 lists certain protection systems that are excluded
from the requirements of PRC-023-1. These systems are specified in
sections 3.1 through 3.9.
a. NOPR Proposal
250. In the NOPR, the Commission stated that it could not determine
whether the exclusions in section 3 are justified because NERC did not
provide the technical rationale behind any of the exclusions.\174\
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\174\ The exclusion of protection systems intended for the
detection of ground fault conditions appears to be unnecessary
because these systems are not load-responsive.
---------------------------------------------------------------------------
251. The Commission also raised specific concerns about section
3.1, which excludes from the Reliability Standard's requirements relay
elements that are enabled only when other relays or associated systems
fail, such as those overcurrent elements enabled only during loss of
potential conditions or elements enabled only during the loss of
communications. The Commission expressed concern that section 3.1 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 explained that if supervising fault detector relays are
not subject to the Reliability Standard, and they 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 them
to operate and unnecessarily disconnect the line; adjacent transmission
lines with similar protection systems and settings would also operate
unnecessarily, resulting in cascading outages. The Commission requested
comments, therefore, on whether the exclusions in section 3 are
technically justified and whether it should direct the ERO to modify
PRC-023-1 by deleting specific sections in section 3. The Commission
also requested comment on whether it should direct the ERO to modify
section 3.1 to clarify that it does not exclude from the requirements
of PRC-023-1 pilot wire protection or current
[[Page 16946]]
differential protection systems supervised by fault detector
relays.\175\
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\175\ The Commission also noted that section 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 before the Commission, the particular
relay elements they involve remain subject to PRC-023-1 until the
relevant Standards are approved by the Commission. Order No. 693-A,
120 FERC ] 61,053 at P 138.
---------------------------------------------------------------------------
b. Comments
252. While NERC acknowledges that specific justification should be
included for those protection systems that ultimately remain excluded
from the Reliability Standard's requirements, NERC opposes removing any
of the exclusions.\176\
---------------------------------------------------------------------------
\176\ NERC Comments at 35.
---------------------------------------------------------------------------
253. With respect to section 3.1, NERC does not share the
Commission's concern and urges it not to direct the removal of
supervising fault detector relays from the list of exclusions. NERC
explains that section 3.1 excludes elements that: (1) Do not respond to
load current; (2) are in use only during very short periods of time to
address short-term conditions; or (3) supervise operation of relay
elements that themselves are subject to the Reliability Standard. NERC
explains that if the supervised relay element itself does not operate
in these cases, the operation of the supervising element should have no
impact on reliability. NERC asserts that if a communications system is
lost, the transmission element must be protected and may need to be
tripped for low magnitude faults approaching load current. NERC argues
that it is preferable to trip one line for loss of communications than
not trip at all, thereby causing mis-coordination and/or stability
problems. NERC adds that the failure of a communications-based
protection system is typically an isolated event.
254. EEI speculates that the intent behind specifically excluding
overcurrent elements enabled only during loss of potential conditions
and elements enabled only during a loss of communications (the specific
examples listed in section 3.1) is to exclude relay system failures
that, for normal utility practice, would result in either emergency
call outs and repairs or next-day call outs and repairs. EEI concludes
that these failures are rare enough to have a limited impact on the
Bulk-Power System.
255. EEI and Ameren support section 3.1 as technically justified
because it allows transmission lines to remain in-service with a level
of fault protection while the failure that required activation of the
section 3.1 relays is repaired, and that the alternative would be to
take the lines or buses out of service.\177\ Ameren cautions that this
alternative would put the system in a less reliable N-1 or N-many
state.
---------------------------------------------------------------------------
\177\ EEI at 27-28; Ameren at 15.
---------------------------------------------------------------------------
256. EEI adds that many long transmission lines proposed to support
the creation of the national grid will require backup protection for
the types of failures discussed in section 3.1. EEI explains that, for
very long lines, the fault currents can be below rated continuous
capability without the 150 percent margin, and that simple schemes are
required for the small periods of time when the backup protection will
be in-service following a loss of potential conditions or
communications. EEI contends that these exceptions only impact one
facility at a time and do not present more risk than removing the
facility.
257. Exelon, Consumers Energy, and IESO/Hydro One also claim that
the exclusions in section 3.1 are justified. Exelon asserts that the
Reliability Standard's goal is to address protective relays that have a
history of contributing to cascades, and that relays enabled only when
other relays or associated systems fail are extremely unlikely to be a
factor in a disturbance because they are enabled so infrequently.
Consumers Energy cautions that the relays excluded in section 3.1 must
be able to respond to relay failures without regard to relay
loadability; otherwise, there is a risk that faults will not be cleared
and there will be cascading outages. IESO/Hydro One argue that the
Commission should approve section 3.1 because the relays it excludes
are incapable of independently opening the circuit breaker; that is,
they require the action of other relays.
258. TAPS argues that NERC should reconsider section 3.1 because
the exclusion of relay elements enabled only when other relays or
associated systems fail depends on the successful operation of a
potential source (potential transformer or capacitor coupled voltage
transformer (CCVT)) or a communication system.\178\ TAPS explains that
the TPL Reliability Standards require planners to plan the system as if
a potential source or communication system has failed (e.g., TPL-003-
0). Although potential sources and communication systems fail
infrequently, TAPS states that it might be consistent with the TPL
Standards for NERC to reconsider the balance of these factors. TAPS
argues, however, that the Commission should not require NERC to
eliminate section 3.1.
---------------------------------------------------------------------------
\178\ TAPS, Attachment 1 at 17.
---------------------------------------------------------------------------
259. In general, commenters contend that the rest of the exclusions
in section 3 have a sound technical basis. Basin argues that the
exclusions address protection systems that have no significant impact
on the reliability of the bulk electric system, and suggests that the
Commission consider the following criteria in determining whether a
system should be subject to PRC-023-1: (1) The frequency with which
that system is enabled; (2) the probability that the system will be
activated when it is enabled; and (3) the effects that the protection
system will have on the Bulk-Power System when it is activated.\179\
Basin argues that protection systems that have a low probability of
being activated when enabled should be excluded from the Reliability
Standard. Likewise, those that, when activated, have an inconsequential
effect on system stability should also be excluded from the Reliability
Standard. The PSEG Companies argue that PRC-023-1 reasonably balances
risks with the potential expenditure of substantial and costly changes
to protection systems.\180\
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\179\ Basin at 12-13.
\180\ PSEG Companies at 12.
---------------------------------------------------------------------------
260. Exelon and Consumers Energy argue that section 3.2, which
excludes relays that are designed to detect ground fault conditions, is
justified because such relays have no significant history of
contributing to cascades. Consumers Energy claims that it would be a
waste of resources to identify, study, and document the behavior of
devices intended for the detection of ground faults, when such devices
are immune to tripping for load currents.
261. Duke asserts that it is unclear whether section 3.3, which
excludes protection systems intended for protection during stable power
swings, is meant for tripping or to block tripping. Duke states that if
the protection is to block tripping, the exclusion is in conflict with
section 2 of Attachment A, as many relays use the same logic to block
for out-of-step conditions and for stable power swings.
262. Exelon states that the relays identified in section 3.5, which
excludes relays used for special protection systems applied and
approved in accordance with Reliability Standards PRC-012 through PRC-
017, are designed along with specific relay settings to assure that a
given power system meets NERC performance requirements. Consumers
Energy asserts that these relay systems are intended for a specific set
of conditions and already
[[Page 16947]]
undergo a stringent review, such that additional review under PRC-023-1
is unnecessary and creates the risk that a special protection system
approved under PRC-012 through PRC-017 may be found non-compliant under
PRC-023-1. Dominion adds that relay elements used only for special
protection systems applied and approved in accordance with PRC-012
through PRC-017 do not present a risk to the reliability of the grid
because the instances in which they operate are rare events that are
addressed and corrected in a timely manner.\181\
---------------------------------------------------------------------------
\181\ Dominion at 8.
---------------------------------------------------------------------------
263. TAPS argues that the exclusions in sections 3.2 through 3.8
are designed to ensure that PRC-023-1 applies where it is needed to
address loadability concerns, but does not interfere with relays that
are not tripped by load current. TAPS adds that section 3.9, which
excludes relay elements associated with DC converter transformers, is
justified because the output of generators and DC line converters is
not changed significantly with the loss of other facilities.\182\
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\182\ TAPS at 27-28.
---------------------------------------------------------------------------
c. Commission Determination
264. After further consideration, and in light of the comments, we
will not direct the ERO to remove any exclusion from section 3, except
for the exclusion of supervising relay elements in section 3.1.
Consequently, we direct the ERO to revise section 1 of Attachment A to
include supervising relay elements on the list of relays and protection
systems that are specifically subject to the Reliability Standard. As
with our other directives in this Final Rule, we do not prescribe this
specific change as an exclusive solution to our reliability concerns
regarding the exclusion of supervising relay elements. As we have
stated, the ERO can propose an alternative solution that it believes is
an equally effective and efficient approach to addressing the
Commission's reliability concerns.\183\
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\183\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 186.
---------------------------------------------------------------------------
265. Supervising elements ensure that a protection system is secure
and does not operate when it should not operate. When a supervising
relay is in place, it acts as a check on the supervised protection
system because both must operate to trip a facility. If a supervising
relay is set below the rating of the line, high loading conditions will
cause it to be ``picked-up,'' i.e., continuously energized and ready to
operate. When this occurs, the supervising relay will no longer be able
to act as a check on the other protection system because the
supervising relay will already have registered that it should operate.
At that point, the supervising relay will be waiting for the supervised
relay to become energized before tripping the protected facility.\184\
---------------------------------------------------------------------------
\184\ It works like an ``and'' condition (0 + 0 = no trip line,
1 + 1 = trip line, 1 + 0 = no trip line). For a supervising relay
like a fault detector to be always ``picked up'' means that the
relay is energized (it is always a ``1'') and is waiting for another
relay to also become energized before tripping a facility.
---------------------------------------------------------------------------
266. For example, current differential protection systems use
communication systems to transmit and compare information between
relays located at both terminals and to initiate the high-speed
tripping of a facility when the difference of currents at the sending
end and receiving end exceeds a threshold setting usually set at a
small fraction of the normal line loading. Since these protection
systems are dependent on communication systems, the protected facility
will trip if communication is lost, even when the line continues to
carry its normal load current, because the difference of the currents
as seen at either end will be the load current which is much larger
than the threshold setting. Consequently, overcurrent relays are
typically used as supervising relays to prevent the protected facility
from tripping if communication is lost. However, if the supervising
relays are energized due to loading conditions, and then communication
is lost, the current differential protection system will operate in the
absence of a fault and the protected facility will trip.
267. NERC asserts that it is preferable to trip one line for loss
of communications than not trip at all, thereby causing mis-
coordination and/or stability problems. We disagree. Protective relays
should not operate during non-fault conditions. The tripping of
facilities for non-fault conditions, like NERC describes, or in the
case of the August 2003 blackout is not desirable system performance.
268. We also disagree with IESO/Hydro One's assertion that the
exclusion of supervising relays from PRC-023-1 is appropriate because
such relays are not capable of independently opening the circuit
breaker. While a supervising relay is not designed to independently
trip a facility by initiating the opening of the circuit breaker, if
that relay is picked up and energized during non-fault conditions, it
is no longer capable of ensuring the security of a protection system
and may result in the unnecessary tripping of the facility it is
protecting. As we explained, if supervising relays are not subject to
the Reliability Standard, 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 them to operate and
unnecessarily disconnect the line.\185\ A more recent example is an
event that occurred on June 27, 2007 where 138 kV transmission lines in
the NPCC region resulted in sequential tripping of the four 138 kV
cable-circuits. The event resulted in the interruption of service to
about 137,000 customers as well as the loss of five generators and six
138 kV transmission lines. This event is the type of situation that
PRC-023-1 is intended to prevent, and illustrates why we must direct
the ERO to modify Attachment A to include supervising relays.
---------------------------------------------------------------------------
\185\ NOPR, FERC Stats. & Regs. ] 32,642 at P 79.
---------------------------------------------------------------------------
269. Although we do not direct the ERO to remove section 3.1 from
the list of excluded protection systems, we find it necessary to
address some comments made in the context of the Commission's proposal.
For example, we disagree with those commenters that suggest that the
Commission should approve section 3.1 because it excludes from the
Reliability Standard's scope relays and protection systems that rarely
operate. These commenters appear to suggest that protection systems
that rarely operate do not pose a risk to the reliability of the Bulk-
Power System. We disagree. A protective relay, as an integral part of
the Bulk-Power System, must be dependable and secure; it must operate
correctly when required to clear a fault and refrain from operating
unnecessarily, i.e., during non-fault conditions or for faults outside
of its zone of protection, regardless of how many times the relay must
actually operate.\186\ Relays must meet this expectation to contribute
to ensuring Reliable Operation of the Bulk-Power System. Consequently,
the notion that any specific relay should be excluded from the
Reliability Standard's scope because it may operate only on rare
occasions is inconsistent with the fundamental principles that make
protective relays an integral part of ensuring Reliable Operation.
---------------------------------------------------------------------------
\186\ These fundamental objectives for protection systems are
consistent if not identical with the ones stated in NERC Planning
Standards III: System Protection and Control, at 43: Dependability--
a measure of certainty to operate when required, Security--a measure
of certainty not to operate falsely.
---------------------------------------------------------------------------
270. We also disagree with Ameren's assertion that removing section
3.1 from the list of exclusions would put the Bulk-Power System in a
``less reliable N-1state.'' As we discuss above, if supervising relays
that are used in
[[Page 16948]]
current differential schemes are excluded from PRC-023-1 and set much
below the line rating, they will trip the protected lines inadvertently
following the loss of communication system forming part of the
protection system.
271. Finally, Duke asserts that section 3.3 is ambiguous with
respect to whether it excludes protection meant for tripping or to
block tripping, and that if it excludes protection meant to block
tripping, it is in conflict with section 2 because many relays use the
same logic to block for out-of-step conditions and for stable power
swings. We clarify that we do not find a conflict between section 3.3,
which excludes from the Reliability Standard's scope any protection
system intended for protection during stable power swings, and section
2, which ensures that out-of-step blocking schemes do not block
tripping during the loading conditions defined within PRC-023-1.
272. Out-of-step schemes, blocking and tripping, are generally
associated with power swing protection applications. Out-of-step
tripping schemes allow controlled tripping during loss of synchronism
during unstable power swings while out-of-step blocking schemes block
tripping during stable power swings. Because out-of-step tripping
relays are supervised by load-responsive overcurrent relays, its
applicability to the requirements of PRC-023-1 is appropriate. Because
the reliability objective of Requirement R1 is to set protective relays
while ``maintaining reliable protection of the bulk-electric system for
all fault conditions,'' as previously determined, out-of-step blocking
schemes must allow tripping for faults during the loading conditions
defined within PRC-023-1. Thus, the reliability goal of the two schemes
for the purposes of PRC-023-1 is different, and consequently, we find
no conflict within the Standard.
J. Effective Date
273. NERC proposed the following effective dates for Requirements
R1 and R2: (1) The beginning of the first calendar quarter following
applicable regulatory approvals for all transmission lines and
transformers with low-voltage terminals operated/connected at and above
200 kV, except for switch-on-to fault-schemes; (2) the beginning of the
first calendar quarter 39 months after applicable regulatory approvals
for all transmission lines and transformers with low-voltage terminals
operated/connected between 100 kV and 200 kV, including switch-on-to
fault-schemes; \187\ and (3) 24 months from notification by the
planning coordinator that, pursuant to the ``add in'' approach, a
facility has been added to the planning coordinator's list of critical
facilities. For Requirement R3, NERC proposed an effective date of 18
months following applicable regulatory approvals.
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\187\ ``Switch-on-to-fault schemes'' are protection systems
designed to trip a transmission line breaker when the breaker is
closed into a fault. Because the current fault detectors for these
systems must be set low enough to detect ``zero-voltage'' faults,
i.e., close-in, three-phase faults, these systems may be susceptible
to operate on load.
---------------------------------------------------------------------------
274. NERC also proposed to include a footnote (exceptions footnote)
to the ``Effective Dates'' section honoring temporary exceptions from
enforcement actions approved by the NERC Planning Committee before NERC
proposed the Reliability Standard.\188\
---------------------------------------------------------------------------
\188\ 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 Standard]
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.
---------------------------------------------------------------------------
1. NOPR Proposal
275. In the NOPR, the Commission proposed to approve NERC's
implementation plan for facilities operated at and above 200 kV. In
light of its applicability proposals, the Commission proposed to reject
the rest of NERC's implementation plan and require, for all sub-200 kV
facilities, an effective date of 18 months following applicable
regulatory approvals. The Commission also proposed to direct NERC to
remove the exceptions footnote, explaining that discussions about
potential enforcement actions are best left out of a Reliability
Standard and instead handled by NERC's compliance and enforcement
program.\189\
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\189\ NOPR, FERC Stats. & Regs. ] 32,642 at P 85-86.
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2. Comments on Effective Date Proposals
276. In general, commenters support the Commission's proposal to
adopt the effective date proposed by NERC for facilities operated at
and above 200 kV, but overwhelmingly oppose the Commission's proposal
for an 18 month effective date for sub-200 kV facilities, regardless of
whether the Commission directs the ERO to adopt the ``rule out''
approach or approves NERC's ``add in'' approach.\190\ Commenters
generally argue that the Commission should adopt NERC's proposal of an
effective date of the beginning of the first calendar quarter 39 months
after applicable regulatory approvals for 100 kV-200 kV facilities.
---------------------------------------------------------------------------
\190\ Commenters argue that a ``rule out'' approach would
require a much longer implementation period, with estimates of up to
12 years.
---------------------------------------------------------------------------
277. NERC argues that planning coordinators will require at least
18 months to identify the 100 kV-200 kV facilities that should be
subject to the Reliability Standard, and possibly an additional 18 to
24 months to complete any design and construction changes necessary to
comply with the Standard. Consumers Energy, EEI, and Oncor offer
similar estimates.
278. APPA argues that NERC's implementation plan gives planning
coordinators the time necessary to perform in-depth studies to identify
which facilities are critical to the reliability of the bulk electric
system, and gives affected entities the time to make any necessary
costly upgrades. APPA adds that only a limited number of experienced
industry experts and consultants will be available to assist entities
in complying with the Reliability Standard, and speculates that their
time will be in high demand.
279. TAPS observes that Order No. 672 recognizes that
implementation timelines must balance any urgency in the need to
implement a Reliability Standard with the reasonableness of the time
allowed for those who must comply to develop the necessary procedures,
software, facilities, staffing or other relevant capability.\191\ TAPS
argues that the Commission should give due weight to NERC's expert
assessment of that balance and adopt the effective dates proposed by
NERC.
---------------------------------------------------------------------------
\191\ TAPS at 29 (citing Order No. 672, FERC Stats. & Regs. ]
31,204 at P 333).
---------------------------------------------------------------------------
3. Comments on Exceptions Footnote
280. EEI argues that the Commission's proposal to direct the ERO to
remove the exceptions footnote is too prescriptive given the
Commission's statutory role in the Reliability Standard development
process. EEI argues that the Commission has gone much farther than
identifying its concern because its proposal does not allow for the ERO
to develop equally effective alternatives.\192\
---------------------------------------------------------------------------
\192\ EEI at 28.
---------------------------------------------------------------------------
281. Oncor and Consumers Energy agree with the Commission's
proposal. Oncor argues that the need for the temporary exemption has
expired and therefore should be removed from the Reliability Standard.
[[Page 16949]]
4. Commission Determination
282. We decline to fully adopt the NOPR proposal and approve all of
NERC's proposed effective dates, including its proposal of 39 months
from the beginning of the first calendar quarter after applicable
regulatory approvals for 100 kV-200 kV facilities. In light of our
decision to approve the ``add in'' approach for 100 kV-200 kV
facilities, and after consideration of the comments, we agree with NERC
that this is an appropriate effective date.
283. Additionally, in light of our directive to the ERO to expand
the Reliability Standard's scope to include sub-100 kV facilities that
Regional Entities have already identified as necessary to the
reliability of the Bulk-Power System through inclusion in the
Compliance Registry, we direct the ERO to modify the Reliability
Standard to include an implementation plan for sub-100 kV facilities.
284. We also direct the ERO to remove the exceptions footnote from
the ``Effective Dates'' section. As the Commission stated in the NOPR,
the exceptions footnote is addressed to potential enforcement actions,
and is therefore best left out of the Reliability Standard and
addressed in NERC's compliance and enforcement program. Moreover, we
agree with Oncor that the need for the temporary exemption has expired
and therefore should be removed from the Reliability Standard. We add
that entities are free to request exceptions through NERC's existing
process, subject to Commission review and approval.
K. Violation Risk Factors
285. Requirement R1 directs entities to set their relays according
to one of the options set forth in sub-requirements R1.1 through R1.13.
NERC assigned Requirement R1 a ``high'' violation risk factor, but did
not assign violation risk factors to sub-requirements R1.1 through
R1.13.
286. Requirement R2 provides that entities that set their relays
according to 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 as to the calculated circuit
capability. NERC assigned Requirement R2 a ``medium'' violation risk
factor.
287. Requirement R3 requires planning coordinators to determine
which sub-200 kV facilities are critical to the reliability of the bulk
electric system and therefore subject to Requirement R1.\193\ NERC
assigned Requirement R3 a ``medium'' violation risk factor.
---------------------------------------------------------------------------
\193\ As proposed by NERC, Requirement R3 directs planning
coordinators to identify the 100 kV-200 kV facilities that should be
subject to Requirement R1. As we have explained, in this Final Rule
we direct that the ERO revise Requirement R3 so that planning
coordinators also identify sub-100 kV facilities that should be
subject to the Reliability Standard.
---------------------------------------------------------------------------
1. NOPR Proposal
288. In the NOPR, the Commission listed the five guidelines that it
uses to evaluate proposed violation risk factor assignments (Violation
Risk Factor Guidelines). According to these Guidelines, violation risk
factor assignments should be consistent: (1) With the conclusions of
the Final Blackout Report; (2) within a Reliability Standard; (3) among
Reliability Standards with similar Requirements; and (4) with NERC's
definition of the violation risk factor level; the Commission also
stated that (5) the violation risk factor levels for Requirements that
co-mingle a higher risk reliability objective and a lower risk
reliability objective must not be watered down to reflect the lower
risk level associated with the less important reliability
objective.\194\
---------------------------------------------------------------------------
\194\ NOPR, FERC Stats. & Regs. ] 32,642 at P 88. For a complete
discussion of each guideline, see North American Electric
Reliability Corp., 119 FERC ] 61,145, P 19-36 (Violation Risk Factor
Order), order on reh'g and compliance filing, 120 FERC ] 61,145
(2007) (Violation Risk Factor Rehearing Order).
---------------------------------------------------------------------------
289. The Commission agreed with NERC that Requirement R1 should be
assigned a ``high'' violation risk factor. The Commission added,
however, that violation of any of the criteria in sub-requirements R1.1
through R1.13 present the same reliability risk as a violation of
Requirement R1 because they set forth the options for compliance with
Requirement R1. Consequently, the Commission proposed to direct the ERO
to assign a ``high'' violation risk factor to each sub-requirement.
290. The Commission also proposed to direct the ERO to modify the
violation risk factor assigned to Requirement R3 and its sub-
requirements to reflect the Commission's applicability proposals.
2. Comments
291. NERC and other commenters oppose the Commission's proposal to
assign a separate violation risk factor to sub-requirements R1.1
through R1.13. These commenters argue that the sub-requirements are
alternative ways to comply with Requirement R1, not separate
Requirements that must be complied with in their own right. The
commenters point out that each sub-requirement is intended to address a
different operating condition or system design condition and that, for
any specific circuit, entities will set their relays pursuant to only
one of the sub-requirements. NERC adds that its proposal to assign
violation risk factors only to Requirement R1 is consistent with its
informational filing in Docket No. RM08-11-000, where it described more
fully its plans for a new, comprehensive approach to assigning
violation risk factors.\195\
---------------------------------------------------------------------------
\195\ In its informational filing, NERC indicates that NERC
drafting teams will develop ``rolled up'' violation risk factors and
violation severity levels.
---------------------------------------------------------------------------
292. An individual commenter, Michael McDonald, argues that
Requirement R1 should have a ``medium'' violation risk factor, rather
than a ``high'' violation risk factor, because actions taken since the
August 2003 blackout have reduced the likelihood that a relay
loadability issue will cause a cascading outage.
3. Commission Determination
293. We approve NERC's assignment of a ``high'' violation risk
factor to Requirement R1 and a ``medium'' violation risk factor to
Requirement R2. These violation risk factor assignments are consistent
with the Violation Risk Factor Guidelines.
294. We disagree with Michael McDonald, who argues that Requirement
R1 should have a ``medium'' violation risk factor rather than a
``high'' violation risk factor. Violation risk factor assignments
represent the risk a violation of a Requirement presents to the Bulk-
Power System.\196\ Although the Commission, the ERO, and industry have
taken actions since the August 2003 blackout to reduce the likelihood
that relay outages will cause cascading outages, these actions do not
mitigate the risk of non-compliance with Requirement R1. In our view, a
violation of Requirement R1 has the potential to put the Bulk-Power
System at the risk of cascading outages like those that occurred during
the August 2003 blackout. Consequently, we agree with the ERO that
Requirement R1 should be assigned a ``high'' violation risk factor.
---------------------------------------------------------------------------
\196\ North American Electric Reliability Corp., 121 FERC ]
61,179, at P 38 (2007).
---------------------------------------------------------------------------
295. We will not require the ERO to assign a violation risk factor
to each sub-requirement of Requirement R1 because we agree with the ERO
that the sub-requirements are alternative ways, based on different
operating or design configurations, of complying with Requirement R1.
Consequently, an entity's failure to appropriately apply
[[Page 16950]]
one of the sub-requirements of Requirement R1 to a specific operating
design or configuration is, as a violation of Requirement R1, subject
to a ``high'' violation risk factor. While the Commission generally
expects that the ERO will assign a violation risk factor to each
Requirement and sub-requirement of a Reliability Standard, we will
accept the ERO's proposal not to assign violation risk factors to sub-
requirements R1.1 through R1.13 as an exception to our current policy
because we are satisfied that the sub-requirements do not constitute
independent compliance requirements separate from Requirement R1.\197\
---------------------------------------------------------------------------
\197\ NERC's assignment of violation risk factors in Reliability
Standard PRC-023-1 appears to be consistent with the approach to
assigning violation risk factors set forth in NERC's informational
filing in Docket No. RM08-11-000. At NERC's request, the Commission
has not acted on the informational filing. The Commission
understands, however, that NERC anticipates formally filing a
comprehensive ``roll up'' plan in the second quarter of 2010.
Consequently, we direct the ERO to re-file the violation risk
factors associated with the Requirements of PRC-023-1 when it
submits its comprehensive plan.
---------------------------------------------------------------------------
296. We also agree with the ERO's decision to assign Requirement R2
a ``medium'' violation risk factor. Requirement R2 comprises two
reliability obligations: (1) The required use of the calculated circuit
capability as the facility rating of the circuit for entities that set
their relays according to sub-requirements R1.6 through R1.9, R1.12, or
R1.13; and (2) the entities' obligation to obtain the agreement of the
planning coordinator, transmission operator, and reliability
coordinator as to the calculated circuit capability. Requirement R2 co-
mingles more than one reliability obligation and, consistent with
Violation Risk Factor Guideline 5, the assigned violation risk factor
reflects the reliability risk of a violation of the higher reliability
obligation (i.e., the requirement to use the calculated circuit
capability as the facility rating of the circuit).
297. Finally, we direct the ERO to assign a ``high'' violation risk
factor to Requirement R3. The Commission expects consistency between
violation risk factors assigned to Requirements that address similar
reliability goals.\198\ NERC assigned a ``high'' violation risk factor
to Requirement R1, which requires entities to set their relays
according to one of the criteria in sub-requirements R1.1 through
R1.13. Requirement R3 directs planning coordinators to determine which
sub-200 kV facilities will be subject to Requirement R1. Since the
facilities identified by the planning coordinator pursuant to
Requirement R3 are required to meet Requirement R1, we conclude that
the reliability risk to the Bulk-Power System of a violation of
Requirement R3 is the same as a violation of Requirement R1. We direct
the ERO to file the new violation risk factor no later than 30 days
after the date of this Final Rule.
---------------------------------------------------------------------------
\198\ Violation Risk Factor Order, 119 FERC ] 61,145 at P 25.
---------------------------------------------------------------------------
L. Violation Severity Levels
298. NERC proposed violation severity levels for Requirements R1,
R2, and R3, but not for sub-requirements R1.1 through R1.13 or R3.1
through R3.3.
299. For Requirement R1, NERC proposed: (1) A ``moderate''
violation severity level when an entity complies with a sub-requirement
of Requirement R1, but has incomplete or incorrect evidence of
compliance; and (2) a ``severe'' violation severity level when an
entity fails to comply with a sub-requirement of Requirement R1, or
when the entity lacks any evidence of compliance.
300. NERC designated Requirement R2 as a ``binary'' Requirement and
proposed a ``lower'' violation severity level when an entity sets its
relays pursuant to sub-requirements R1.6 through R1.9, R1.12, or R1.13,
but lacks evidence that it obtained the agreement of the planning
coordinator, transmission operator, and reliability coordinator as to
the calculated circuit capability.\199\
---------------------------------------------------------------------------
\199\ ``Binary'' Requirements are Requirements where compliance
is defined in terms of ``pass'' or ``fail.''
---------------------------------------------------------------------------
301. For Requirement R3, NERC proposed: (1) A ``severe'' violation
severity level when an entity lacks a process to identify critical
facilities; and (2) ``moderate'' and ``high'' violation severity levels
based on the number of days that a planning coordinator is late in
providing the critical facilities list to the entities that must
receive it.
1. NOPR Proposal
302. In the NOPR, the Commission listed the four guidelines that it
uses to evaluate proposed violation severity levels (Violation Severity
Level Guidelines).\200\ According to these Guidelines, violation
severity levels should: (1) Avoid the unintended consequence of
lowering the current level of compliance; (2) ensure uniformity and
consistency among all approved Reliability Standards in the
determination of penalties; \201\ (3) be consistent with the
corresponding Requirement; and (4) be based on a single violation, not
on a cumulative number of violations.
---------------------------------------------------------------------------
\200\ For a complete discussion of each guideline, see North
American Electric Reliability Corporation, 123 FERC ] 61,284, at P
19-36 (Violation Severity Level Order), order on reh'g and
compliance filing, 125 FERC ] 61,212 (2008) (Violation Severity
Level Rehearing Order).
\201\ In the Violation Severity Level Order, the Commission
identified two specific concerns with the uniformity and consistency
of the violation severity level assignments then under review: (a)
The single violation severity levels assigned to individual binary
requirements were not consistent; and (b) the violation severity
level assignments contained ambiguous language. With respect to
concern identified in (a), which the Commission referred to as
``Guideline 2a,'' the Commission explained that NERC assigned
different violation severity levels to different binary Requirements
(i.e. pass/fail Requirements) without justifying the different
assignments or explaining how they were consistent with the
application of a basic pass/fail test. The Commission directed NERC
to modify the violation severity levels by either: (1) Consistently
applying the same severity level to each binary Requirement; or (2)
changing from a binary approach to a gradated approach. Violation
Severity Level Order 123 FERC ] 61,284 at P 23-27, 45-47. In its
compliance filing, NERC chose the first option and proposed to apply
a ``severe'' violation severity level to each of the binary
Requirements. The Commission agreed with this approach. North
American Electric Reliability Corporation, 127 FERC ] 61,293, at P
5, 11 (2009).
---------------------------------------------------------------------------
303. The Commission observed that the violation severity levels
assigned to Requirements R1 and R2 appear to be inconsistent with
Violation Severity Level Guideline 3. The Commission noted that the two
violation severity levels proposed for Requirement R1 address both: (1)
The severity of a violation (i.e., the fact that relay settings do not
comply with Requirement R1); and (2) facts necessarily associated with
evaluating compliance (i.e., the existence of evidence that relay
settings comply with Requirement R1). The Commission explained that
Requirement R1 does not require evidence of compliance, only
compliance. Similarly, the Commission stated that the single violation
severity level proposed for Requirement R2 does not reflect the
severity of a violation of Requirement R2, but the severity of lacking
evidence of compliance with Requirement R2. Consequently, the
Commission proposed to direct the ERO to: (1) Adopt a binary approach
to Requirement R1; i.e., assign a violation severity level based on
whether or not the entity complies with Requirement R1; and (2) assign
a violation severity level for Requirement R2 that addresses an
entity's failure to comply with the entire Requirement; i.e., its
failure to calculate circuit capability as the facility rating and
obtain agreement on that rating with the required entities. The
Commission also proposed to direct the ERO to assign a single violation
severity level to each sub-requirement in Requirement R1.
[[Page 16951]]
304. The Commission also stated that the single violation severity
level assigned to Requirement R2 appears to be inconsistent with NERC's
Guideline 2a compliance filing in Docket No. RR08-4-004.\202\ The
Commission explained that, in that docket, NERC assigned ``severe''
violation severity levels to binary Requirements. The Commission added
that it expects the violation severity levels assigned to binary
requirements to be consistent, and proposed to direct the ERO to revise
the violation severity level assigned to Requirement R2 to be
consistent with Guideline 2a.
---------------------------------------------------------------------------
\202\ See supra n. 202.
---------------------------------------------------------------------------
305. Finally, in light of its proposals to direct the ERO to modify
Requirement R3 and its sub-requirements, the Commission proposed to
direct the ERO to assign new violation severity levels to Requirement
R3 and its sub-requirements, consistent with the Violation Severity
Level Guidelines.
2. Comments
306. NERC agrees with the Commission's proposal to review the
violation severity levels in accordance with the Violation Severity
Level Guidelines.\203\ Other commenters oppose the Commission's
proposal to assign a violation severity level to each sub-requirement
in Requirement R1 for the same reasons that they oppose assigning a
violation risk factor to each sub-requirement in Requirement R1.
---------------------------------------------------------------------------
\203\ NERC Comments at 40.
---------------------------------------------------------------------------
307. Consumers Energy makes the general argument that ``evidence''
should be included in Requirements only when the compliance monitor
(e.g., the Regional Entity or NERC) uses it for a reliability purpose.
Consumers Energy argues that if evidence is used only to determine
whether an entity is in compliance with a Reliability Standard, the
evidence should be instead represented in a Measure as reflected in
PRC-023-1.
3. Commission Determination
308. We adopt the NOPR proposals with respect to the violation
severity levels assigned to Requirements R1 and R2. As we explained in
the NOPR, the violation severity levels assigned to Requirement R1 are
inconsistent with Violation Severity Guideline 3 because they are based
in part on the amount of evidence of compliance that an entity can
produce, even though Requirement R1 does not require entities to have
evidence of compliance. Consequently, we direct the ERO to assign a
single violation severity level of ``severe'' for violations of
Requirement R1.
309. While we adopt the NOPR proposal with respect to Requirement
R1, we do not adopt the NOPR proposal to direct the ERO to assign
individual violation severity levels to the sub-requirements of
Requirement R1. As we explained with respect to the violation risk
factors, we will make an exception to our general policy because we are
satisfied that the sub-requirements of Requirement R1 do not constitute
independent compliance requirements separate from Requirement R1.\204\
---------------------------------------------------------------------------
\204\ Consistent with our treatment of violation risk factors,
we direct the ERO to re-file the violation severity factors
associated with the Requirements of PRC-023-1 when it submits its
comprehensive plan.
---------------------------------------------------------------------------
310. We also adopt the NOPR proposal with respect to the violation
severity level assigned to Requirement R2. As the Commission pointed
out in the NOPR, the single violation severity level assigned to
Requirement R2 suffers from the same problem as the two violation
severity levels assigned to Requirement R1; namely, it is based in part
on whether an entity has evidence of compliance with the Requirement,
even though the Requirement itself does not require an entity to have
evidence of compliance. Additionally, Requirement R2 is a binary
Requirement, and NERC's assignment of a ``lower'' violation severity
level rather than a ``severe'' violation severity level is inconsistent
with its Guideline 2a compliance filing in Docket No. RR08-4-004. In
that filing, NERC assigned a ``severe'' violation severity level to
binary Requirements. As the Commission stated when discussing Guideline
2a in the Violation Severity Level Order, single violation severity
levels assigned to binary requirements should be consistent.
Accordingly, we direct the ERO to change the violation severity level
assigned to Requirement R2 from ``lower'' to ``severe'' to be
consistent with Guideline 2a.
311. Finally, we direct the ERO to assign a ``severe'' violation
severity level to Requirement R3. Requirement R3 directs planning
coordinators to identify the critical sub-200 kV facilities that are
subject to the Reliability Standard. Similar to our determination for
Requirement R2, it is our view that Requirement R3 is a binary
requirement; either the planning coordinator identified critical
facilities or it did not. Consequently, we find that Requirement R3
must have a single violation severity level of ``severe.''
312. We direct the ERO to file the new violation severity levels
described in our discussion no later than 30 days after the date of
this Final Rule.
M. Miscellaneous
1. Purpose of the Reliability Standard
313. The Reliability Standard's stated purpose is to ``require[]
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.''
a. Comments
314. BPA argues that the Commission should direct the ERO to revise
the Reliability Standard's stated purpose because the Standard requires
only that certain protective relays refrain from operating during
permissible load conditions and does not require that protective relays
reliably detect and protect the electric network from all fault
conditions. BPA asserts that sub-requirement R1.12 touches on the
subject of adequately detecting faults by allowing the loadability
requirements of relay settings to be relaxed in order to allow adequate
protection, but adds that neither sub-requirement R1.12 nor any other
sub-requirement requires relays to be set to reliably detect ``all''
fault conditions and protect the electrical network from these faults.
BPA argues that the class of relays covered by the Reliability Standard
is not even capable of detecting ``all'' fault conditions. BPA
requests, therefore, that the Commission direct the ERO to revise the
Reliability Standard's stated purpose to be: ``[t]o prevent certain
protective relays from operating under permissible transmission line
and equipment loads.'' \205\
---------------------------------------------------------------------------
\205\ BPA at 1-2.
---------------------------------------------------------------------------
b. Commission Determination
315. We disagree with BPA. Requirement R1 directs entities to set
their relays according to one of its sub-requirements (R1.1 through
R1.13), based on their transmission configurations. No matter what
setting entities choose, they are required to apply it while
``maintaining reliable protection of the bulk electric system for all
fault conditions.'' Thus, any sub-requirement that an entity implements
must protect the electric network from all fault conditions.
[[Page 16952]]
2. Transmission Facility Design Margin
a. Comments
316. Basin interprets the Commission's statement in the NOPR that
``[s]ub-requirement R1.1 specifies transmission line relay settings
based on the highest seasonal facility rating using the 4-hour thermal
rating of a line, plus a design margin of 150 percent'' to suggest that
the Commission incorrectly assumed that relay margins include an
additional transmission facility design margin, and that additional
Total Transfer Capability (TTC) can be achieved with different relay
settings. Basin states that relay operations do not affect the
calculation of TTC because relay settings are established above the
level of standard operation of the system and will not operate when
facilities are loaded at their maximum ratings.
b. Commission Determination
317. We clarify that the Commission did not assume that ``design
margin,'' as it is used in the context of the Reliability Standard,
equates to additional TTC on the transmission facility. The statement
in the NOPR that Basin refers to is a direct quote from NERC where NERC
describes ``design margin'' in the context of the margin (percentage)
over the 4-hour facility rating protective relay setting criteria for
sub-requirement R1.1.\206\ The ``design margin'' described in this
requirement is different than the ``transmission reliability margin''
that accounts for the inherent uncertainty in bulk electric system
conditions in the calculation of TTC established in the Modeling, Data,
and Analysis (MOD) Reliability Standards.
---------------------------------------------------------------------------
\206\ NERC Petition at 9.
---------------------------------------------------------------------------
IV. Information Collection Statement
318. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\207\ The information collection
requirements in this Final Rule are identified under the Commission
data collection, FERC-725G ``Transmission Relay Loadability Mandatory
Reliability Standard for the Bulk Power System.'' Under section 3507(d)
of the Paperwork Reduction Act of 1995,\208\ the proposed reporting
requirements in the subject rulemaking will be submitted to OMB for
review. Interested persons may obtain information on the reporting
requirements by contacting the Federal Energy Regulatory Commission,
888 First Street, NE., Washington, DC 20426 (Attention: Michael Miller,
Office of the Executive Director, 202-502-8415) or from the Office of
Management and Budget (Attention: Desk Officer for the Federal Energy
Regulatory Commission, fax: 202-395-7285, e-mail: [email protected]).
---------------------------------------------------------------------------
\207\ 5 CFR 1320.11.
\208\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------
319. The ``public protection'' provisions of the Paperwork
Reduction Act of 1995 requires each agency to display a currently valid
control number and inform respondents that a response is not required
unless the information collection displays a valid OMB control number
on each information collection or provides a justification as to why
the information collection number cannot be displayed. In the case of
information collections published in regulations, the control number is
to be published in the Federal Register.
320. Public Reporting Burden: In the NOPR, the Commission based its
estimate of the Public Reporting Burden on the NERC Compliance
Registry, as of March 3, 2009, and on NERC's July 30, 2008 petition for
approval of PRC-023-1. The Commission stated that, as of March 3, 2009,
NERC had registered in its Compliance Registry: (1) 568 distribution
providers; (2) 825 generator owners; (3) 324 transmission owners; and
(4) 79 planning authorities. The Commission also noted that the
Reliability Standard does not apply to all transmission owners,
generator owners, and distribution providers, but only to those with
load-responsive phase protection systems as described in Attachment A
of the Standard, applied to all transmission lines and transformers
with low-voltage terminals operated or connected at 200 kV and above
and between 100 kV and 200 kV as identified by the planning coordinator
as critical to the reliability of the bulk electric system. The
Commission further noted that 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 parameters, the Commission estimated the Public Reporting
Burden as follows:
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of Number of
Data collection respondents responses Hours per respondent Total annual hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC-725G:
M1--TOs, GOs and DPs must ``have 450 1 Reporting: 0........................... Reporting: 0.
evidence'' to show that each of its
transmission relays are set according
to Requirement R1.
Recordkeeping: 100..................... Recordkeeping: 45,000.
M2--Certain TOs, GOs and DPs must have 166 1 Reporting: 0........................... Reporting: 0.
evidence that a facility rating was
agreed to by PA, TOP and RC.
Recordkeeping: 10...................... Recordkeeping: 1,660.
M3--PC must document process for 79 1 175.................................... 13,825.
determining critical facilities and
(2) a current list of such facilities.
-----------------------------------------------------------------------------------------------------------------
Total............................. .............. .............. ....................................... 60,485.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Based on the available information from the compliance registry,
the Commission estimated that 525 entities would be responsible for
compliance with the Reliability Standard.\209\ The Commission also
estimated that it would require 60,485 total annual hours for
collection (reporting and recordkeeping) and that the average
annualized cost of compliance would be $2,419,400 ($40/hour for 60,485
hours; the Commission based the $40/hour estimate on $17/hour for a
file/record clerk and $23/hour for a supervisor).\210\
---------------------------------------------------------------------------
\209\ NOPR, FERC Stats. & Regs. ] 32,642 at P 117.
\210\ BPA notes that the NOPR erroneously showed this figure as
$241,940 rather than $2,419,400.
---------------------------------------------------------------------------
321. Several commenters express concern with the burden to be
imposed by the Reliability Standard. Some of these comments address the
Reliability Standard's potential impact on small entities; because
these comments are also the subject of the analysis
[[Page 16953]]
performed under the Regulatory Flexibility Act, the Commission has
provided a response under that section of this rulemaking. Other
comments question the Commission's initial burden estimate.
322. APPA argues that the Commission has grossly underestimated the
Public Reporting Burden and requests that the Commission develop a more
accurate estimate. APPA notes that the Commission provided a breakdown
by category of registered entities for a total of 1,717 entities, but
then asserts that only 525 entities will be subject to PRC-023-1 as
proposed by NERC. APPA states that it cannot assess how the Commission
came up with this lower number, as the Commission provided no
explanation of its methodology or the data it used to reach this
conclusion. APPA states that the Commission's initial estimate appears
to be based on the Reliability Standard as proposed by NERC, and
therefore fails to account for the Commission's proposals to expand the
Standard's applicability. APPA argues that the Commission must assess
the Public Reporting Burden created by its proposals.
323. APPA also claims that the Commission's estimate of labor costs
is so low as to be completely erroneous for burden evaluation purposes.
Based on an informal survey of its members that own or operate
transmission facilities above 100 kV, APPA states that 21 out of nearly
300 registered public power utilities would need to evaluate 791
terminals to comply with the Commission's proposals. At an estimated
cost of between $500 and $1,200 per location, APPA estimates that the
cost of compliance for these 21 members would be between $395,500 and
$949,200; the Commission estimated $2,419,400 for the entire industry.
APPA adds that entities will need seasoned and expensive electrical
engineers and outside consultants to comply with the Commission's
proposals, not file/record clerks who are paid $17 per hour or
supervisory personnel who are paid $23 per hour. APPA reports that one
of its members estimates that it would have to use engineers, managers
and even director-level personnel to carry out the required tasks, at
an estimated cost of $55-$75 per hour. APPA expects that the cost of
external consultants could reach $200 per hour.
324. BPA states that the loaded cost for an engineer is
approximately $80 per hour, twice the $40 per hour the Commission
estimated for a file clerk and a supervisor. BPA observes that this
would double the estimated annual cost of the Reliability Standard to
$4,838,800. BPA also questions the estimate of 100 hours annually for
each respondent to comply with Requirement R1. BPA states that it could
take thousands of hours for larger utilities.
325. EEI argues that the Commission's estimate of hours for
reporting and recordkeeping substantially underestimates the actual
cost, in both time and money, required to comply with the Commission's
modifications. EEI reports that one smaller investor-owned utility has
estimated that it would take 4-8 hours of engineering time, per relay
terminal, to review the more than 850 line terminals on its system
operated between 100 kV and 200 kV. EEI states that it would take an
additional 6-12 hours of engineering time per terminal if, as the
utility expects, about one third of its line terminals require
mitigation, and another 6-12 hours of operations and maintenance staff
hours to implement relay settings for terminals requiring mitigation.
326. EEI asserts that it could cost $40,000 to replace each
terminal in order to comply with the Commission's modifications. EEI
states that there are more than 100,000 line terminals in the U.S. on
facilities between 100 kV and 200 kV that would have to be checked if
the Commission adopts a ``rule out'' approach. EEI estimates that this
review could take 1.5 million labor hours, and another 750,000 hours if
just one-half of the terminals must be replaced. EEI states that the
aggregate cost to replace these terminals could exceed $2.4 billion.
327. Given the Commission's decision not to adopt the ``rule out''
approach, most of these comments are no longer relevant. However, in
response to the comments that remain relevant, and upon further review,
we have revised our initial estimates as reflected below.
Information Collection Costs: The Commission sought comments about
the information collection costs needed to comply with PRC-023-1. Since
many of the comments the Commission received estimated costs based on
the ``rule out'' approach, they are no longer applicable given our
decision in this Final Rule not to require the ``rule out'' approach.
However, some commenters argue, apart from the ``rule out'' approach,
that the NOPR underestimated the hours required to comply and the
estimated cost of labor. After further consideration, with respect to
the costs of labor, we agree that the $40/hour estimate for file/record
clerks and supervisory employees is not correct. We also agree with
commenters that electrical engineers will be required to comply with
PRC-023-1. Therefore, we have revised estimates as indicated below:
Number of line terminals to be reviewed: 53,000.
Number of hours per terminal: 6.4.
Hourly rate for review by engineers: $120.
Total Cost for review = (terminals to be reviewed x hours per terminal)
x hourly rate for review by engineers = (53,000 x 6.4) x ($120/hour) =
339,200 hours x 120/hour = $40,704,000.
Sources
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.
328. 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: [email protected]]. 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: [email protected].
V. Environmental Analysis
329. 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
[[Page 16954]]
environment.\211\ 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.\212\ Accordingly, neither an environmental
impact statement nor environmental assessment is required.
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\211\ Order No. 486, Regulations Implementing the National
Environmental Policy Act, 52 FR 47,897 (Dec. 17, 1987), FERC Stats.
& Regs. ] 30,783 (1987).
\212\ 18 CFR 380.4(a)(5) (2009).
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VI. Regulatory Flexibility Act
330. The Regulatory Flexibility Act of 1980 (RFA) \213\ generally
requires a description and analysis of any final rule that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking, but
rather requires consideration of alternatives that are less burdensome
to small entities and an agency explanation of why alternatives were
rejected.
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\213\ 5 U.S.C. 601-612.
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331. In drafting a rule, an agency is required to: (1) Assess the
effect that its regulation will have on small entities; (2) analyze
effective alternatives that may minimize a regulation's impact; and (3)
make the analyses available for public comment.\214\ In its NOPR, the
agency must either include an Initial Regulatory Flexibility Act
Analysis (Initial Analysis) \215\ or certify that the proposed rule
will not have a ``significant impact on a substantial number of small
entities.''\216\
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\214\ 5 U.S.C. 601-604.
\215\ 5 U.S.C. 603(a).
\216\ 5 U.S.C. 605(b).
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332. If, in preparing the NOPR, an agency determines that the
proposal could have a significant impact on a substantial number of
small entities, the agency shall ensure that small entities will have
an opportunity to participate in the rulemaking procedure.\217\
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\217\ 5 U.S.C. 609(a).
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333. In its Final Rule, the agency must also either prepare a Final
Regulatory Flexibility Act Analysis (Final Analysis) or make the
requisite certification. Based on the comments the agency receives on
the NOPR, it can alter its original position as expressed in the NOPR
but it is not required to make any substantive changes to the proposed
regulation.
334. The statute provides for judicial review of an agency's final
RFA certification or Final Analysis.\218\ An agency must file a Final
Analysis demonstrating a ``reasonable, good-faith effort'' to carry out
the RFA mandate.\219\ However, the RFA is a procedural, not a
substantive, mandate. An agency is only required to demonstrate a
reasonable, good faith effort to review the impact the proposed rule
would place on small entities, any alternatives that would address the
agency's and small entities' concerns and their impact, provide small
entities the opportunity to comment on the proposals, and review and
address comments. An agency is not required to adopt the least
burdensome rule. Further, the RFA does not require an agency to assess
the impact of a rule on all small entities that may be affected by the
rule, only on those entities that the agency directly regulates and
that are subject to the requirements of the rule.\220\
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\218\ 5 U.S.C. 611.
\219\ United Cellular Corp. v. FCC, 254 F.3d 78, 88 (DC Cir.
2001); Alenco Commc'ns, Inc. v. FCC, 201 F.3d 608, 625 (5th Cir.
2000).
\220\ Mid-Tex Elec. Coop., Inc. v. FERC, 773 F.2d 327 (DC Cir.
1985).
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A. NOPR Proposal
335. In the NOPR, the Commission asserted that 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 will apply, do
not fall within the applicable definition of ``small entities.'' The
Commission also stated that, based on available information regarding
NERC's compliance registry, approximately 525 entities will be
responsible for compliance with the new Reliability Standard.
Consequently, the Commission certified that the Reliability Standard
will not have a significant adverse impact on a substantial number of
small entities and that no RFA analysis was required.
B. Comments
336. APPA, TAPS, NRECA, and SWTDUG argue that the ``rule out''
approach for 100 kV-200 kV facilities and the ``add in'' approach for
sub-100 kV facilities will cause the Reliability Standard to have a
significant adverse impact on a substantial number of small entities.
337. NRECA argues that the Commission's Initial Analysis is
inadequate and its conclusion premature given the Commission's
proposals to expand the Reliability Standard's applicability. NRECA
argues that the Commission cannot develop an adequate Final Analysis
without an Initial Analysis that lays the proper foundation for
eliciting comments and seeking information. APPA argues that the
Commission's Initial Analysis is flawed and fails to: (1) Assess the
effect the regulation will have on small entities; (2) analyze
effective alternatives that might minimize the regulation's impact; and
(3) make such an analysis available for public comment.
338. APPA and NRECA also argue that the Commission failed to: (1)
Provide its basis for claiming that only 525 entities from the NERC
Compliance Registry will be required to comply with the Reliability
Standard; (2) justify its assertion that the majority of the expected
525 entities required to comply do not qualify as small entities under
the Small Business Act; (3) state how many of the 525 affected entities
are small entities; and (4) identify the registered entities that are
required to comply. APPA argues that the Commission's expectation that
525 facilities will be required to comply with the Reliability Standard
is based on the Reliability Standard as proposed by NERC, and does not
account for the Commission's potentially broader applicability
proposals. APPA states that 261 of its members are registered entities
and qualify as small entities. NRECA adds that a substantial majority
of its approximately 930 rural electric cooperative members are small
entities that would be adversely impacted by the proposed rule.
339. TAPS argues that the ``rule out'' approach will increase the
burden on small systems and may force the Commission to depart from the
Compliance Registry criteria that formed the basis for its RFA
certification in Order No. 693. TAPS explains that if the ``rule out''
approach will make all 100 kV facilities subject to the Reliability
Standard, including radial transmission lines, then the Standard will
apply to unregistered small entities that have not previously been
considered part of the bulk electric system and therefore do not appear
on the Compliance Registry that served as the basis for the
Commission's small entity impacts analysis.
C. Commission Determination
340. As discussed previously in this Final Rule, the Commission
will not adopt the NOPR proposal to make PRC-023 applicable to all
facilities operated at or above 100 kV, ``ruling out'' those facilities
that would not demonstrably result in cascading outages, instability,
uncontrolled separation, violation of facility ratings, or interruption
of firm transmission service. Accordingly, to
[[Page 16955]]
the extent that the Commission has decided to abandon the ``rule out''
approach in favor of an ``add-in'' approach, as discussed in previous
portions of this Final Rule, the Commission expects that many of the
concerns and impact estimates submitted by commenters are moot or no
longer accurate.
341. Nonetheless, the Commission does find it appropriate to
address commenters' concern regarding the number of entities that the
Commission estimates will be subject to PRC-023-1 as proposed by NERC.
Based on the Compliance Registry dated November 30, 2009, there are 573
entities registered as Distribution Providers, 821 entities registered
as Generator Owners, 323 entities registered as Transmission Owners,
and 80 entities registered as Planning Authorities. However, the
Commission notes that some entities are registered for multiple
functions, and therefore recognizes that there is some overlap between
the entities registered as a Distribution Provider, Transmission Owner,
Generator Owner, and/or Planning Authority. Therefore, after
eliminating any duplicative registrations, the Commission finds that
there are 1301 entities that are registered as engaging in one or more
of the applicable functions within the scope of PRC-023-1.
342. Reliability Standard PRC-023-1 applies to Transmission Owners,
Generator Owners, and Distribution Providers with load-responsive phase
protection systems as described in Attachment A of the Reliability
Standard, applied to facilities defined in requirements 4.1.1 through
4.1.4.\221\ The Reliability Standard applies to facilities 100 kV and
above and to transformers with low-voltage terminals 200 kV and above.
Because there are no commercial generators with a terminal voltage as
high as 100 kV and all generator step-up and auxiliary power
transformers have low-voltage windings well below 200 kV, PRC-023-1
excludes generators and all generator step-up and auxiliary
transformers. Therefore, no generator owner that is not also a
transmission owner and/or a distribution provider will be subject to
PRC-023-1. Accordingly, the Commission calculates that the potential
applicability of the Final Rule may be reduced by 623, which is the
total number of entities registered solely as a generator owner. Thus,
the Commission anticipates that the Final Rule will apply to
approximately 678 entities overall.\222\
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\221\ As proposed, the Commission notes PRC-023-1 is applicable
to 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., however, excludes generator protection relays that
are susceptible to load in Section (3) of Attachment A.
\222\ The Commission derives this result by using the following
equation: 1301 applicable entities (entities registered as one of
more of the following functions: Distribution Provider, Transmission
Owner, Generator Owner, and Planning Authority)--623 entities
registered solely as a Generator Owner = 678.
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343. According to the Department of Energy's Energy Information
Administration (EIA), there were 3271 electric utility companies in the
United States in 2007,\223\ and approximately 3012 of these electric
utilities qualify as small entities under the Small Business Act (SBA)
definition.\224\ Of those 3012 small entities, only 80 entities also
appear in the NERC Compliance Registry. Accordingly, the Commission
estimates that the Reliability Standard will affect a maximum of 80
SBUs, or approximately 12 percent of those entities estimated to be
subject to the requirements of the Final Rule.
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\223\ See U.S. Energy Information Administration, Form EIA-861,
Dept. of Energy (2007), available at http://www.eia.doe.gov/cneaf/electricity/page/eia861.html.
\224\ 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 preceeding year.
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344. Based upon on this revised analysis, we certify that this
Final Rule will not have a significant economic impact on a substantial
number of small entities. Accordingly, no further RFA analysis is
required.
VII. Document Availability
345. 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.
346. 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.
347. 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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
VIII. Effective Date and Congressional Notification
348. These regulations are effective 45 days from publication in
Federal Register for non-major rules and 60 days from the later of the
date Congress receives the agency notice or the date the rule is
published in the Federal Register. The Commission has determined, with
the concurrence of the Administrator of the Office of Information and
Regulatory Affairs of OMB, that this rule is not a ``major rule'' as
defined in section 351 of the Small Business Regulatory Enforcement
Fairness Act of 1996.
List of Subjects in 18 CFR Part 40
By the Commission.
Kimberly D. Bose,
Secretary.
Note: The following Appendix will not appear in the Code of
Federal Regulations.
Appendix A--Commenters
----------------------------------------------------------------------------------------------------------------
Abbreviation Commenter
----------------------------------------------------------------------------------------------------------------
Alcoa.................................................... Alcoa, Inc.
Ameren................................................... Ameren Services Company.
APPA..................................................... American Public Power Association.
ATC...................................................... American Transmission Company, LLC.
Austin Energy............................................ City of Austin, Texas.
Basin.................................................... Basin Electric Cooperative.
BPA...................................................... Bonneville Power Administration.
California Commission.................................... Public Utilities Commission of the State of
California.
City Utilities of Springfield............................ City Utilities of Springfield, Missouri.
[[Page 16956]]
Consumers Energy......................................... Consumers Energy Company.
CRC...................................................... Colorado River Commission of Nevada.
Dominion................................................. Dominion Resources, Inc.
Duke..................................................... Duke Energy Corporation.
EEI...................................................... Edison Electric Institute.
ElectriCities............................................ ElectriCities of North Carolina, Inc.
Entergy.................................................. Entergy Services, Inc.
E.ON..................................................... E.ON U.S. LLC.
EPSA..................................................... Electric Power Supply Association.
ERCOT.................................................... Electric Reliability Council of Texas, Inc.
Exelon................................................... Exelon Corporation.
Fayetteville Public Works Commission..................... Fayetteville Public Works Commission.
Filing Cooperatives...................................... Mohave Electric Cooperative, Inc., Trico Electric
Cooperative, inc., Navopache Electric Cooperative,
Inc., and Sulphur Springs Valley Electric
Cooperative, Inc.
Georgia Transmission..................................... Georgia Transmission Corporation.
IESO/Hydro One........................................... Independent Electricity System Operator and Hydro One
Networks Inc.
IRC...................................................... The ISO/RTO Council.
ISO New England.......................................... ISO New England Inc.
ITC...................................................... International Transmission Company.
Joint Commenters......................................... Independent Electricity System Operator, PJM
Interconnection L.L.C., Southwest Power Pool, and
Midwest Independent Transmission Operator.
LES...................................................... Lincoln Electric System.
Manitoba Hydro........................................... Manitoba Hydro.
McDonald................................................. Michael McDonald.
MDEA Cities.............................................. Mississippi Delta Energy Agency, Clarksdale Public
Utilities Commission of the City of Clarksdale,
Mississippi, and the Public Service Commission of
Yazoo City of the City of Yazoo City, Mississippi.
MEAG..................................................... Municipal Electric Authority of Georgia.
NARUC.................................................... National Association of Regulatory Utility
Commissioners.
NERC..................................................... North American Electric Reliability Corporation.
New York Commission...................................... New York State Public Service Commission.
NRECA.................................................... National Rural Electric Cooperative Association.
NV Energy................................................ NV Energy.
NWCP..................................................... Northern Wasco County People's Utility District.
Oncor.................................................... Oncor Electric Delivery Company LLC.
Ontario Generation....................................... Ontario Power Generation Inc.
PacifiCorp............................................... PacifiCorp.
Pacific Northwest State Commissions...................... Washington Utilities and Transportation Commission,
Idaho Public Utilities Commission, Public Utility
Commission of Oregon, and Montana Public Service
Commission.
Palo Alto................................................ City of Palo Alto, California.
PG&E..................................................... Pacific Gas & Electric Company.
Portland General......................................... Portland General Electric Company.
PSEG Companies........................................... Public Service Electric & Gas Company, PSEG Energy
Resources & Trade LLC, PSEG Power LLC.
Public Power Council..................................... Public Power Council.
Seattle City Light....................................... Seattle City Light.
Six California Cities.................................... Cities of Anaheim, Azusa, Banning, Colton, Pasadena,
and Riverside, California.
SoCalEd.................................................. Southern California Edison Company.
South Carolina E&G....................................... South Carolina Electric & Gas Company.
Southern................................................. Southern Company Services, Inc.
SRP...................................................... Salt River Project Agricultural Improvement and Power
District.
SWTDUG................................................... Southwest Transmission Dependent Utility Group.
TANC..................................................... Transmission Agency of Northern California.
TAPS..................................................... Transmission Access Policy Study Group.
Tri-State................................................ Tri-State Generation & Transmission Association.
TVA...................................................... Tennessee Valley Authority.
WAPA-RMR................................................. Western Area Power Administration-Rocky Mountain
Region.
WECC..................................................... Western Electricity Coordinating Council Relay Work
Group.
Y-WEA.................................................... Y-W Electric Association, Inc.
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[FR Doc. 2010-6568 Filed 4-1-10; 8:45 am]
BILLING CODE 6717-01-P