Document ID: FERC-2009-0781-0003
Agency: ferc
Document Type: Rule
Title: Transmission Relay Loadability Reliability Standard
Posted Date: 2010-04-02T04:00Z

[Federal Register: April 2, 2010 (Volume 75, Number 63)]
[Rules and Regulations]               
[Page 16913-16956]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr02ap10-15]                         

[[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

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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.
---------------------------------------------------------------------------

    \29\ Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \73\ ISO New England at 3. See also Order No. 693, FERC Stats. & 
Regs. ] 31,242, at P 101.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
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    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \139\ Id. P 186.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
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    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \173\ See also Duke and IESO/Hydro One.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \189\ NOPR, FERC Stats. & Regs. ] 32,642 at P 85-86.
---------------------------------------------------------------------------

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: oira_
submission@omb.eop.gov).
---------------------------------------------------------------------------

    \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: michael.miller@ferc.gov]. Comments on the 
requirements of the proposed rule may also be sent to the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy 
Regulatory Commission], e-mail: oira_submission@omb.eop.gov.

V. Environmental Analysis

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \213\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \214\ 5 U.S.C. 601-604.
    \215\ 5 U.S.C. 603(a).
    \216\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \217\ 5 U.S.C. 609(a).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

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.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2010-6568 Filed 4-1-10; 8:45 am]
BILLING CODE 6717-01-P