[Federal Register: April 2, 2010 (Volume 75, Number 63)]
[Rules and Regulations]
[Page 16913-16956]
[DOCID:fr02ap10-15]

-----------------------------------------------------------------------

Part II

Department of Energy

-----------------------------------------------------------------------

Federal Energy Regulatory Commission

-----------------------------------------------------------------------

18 CFR Part 40

Transmission Relay Loadability Reliability Standard; Final Rule

-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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.<PHONE_NUMBER>.

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

(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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

    \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).

---------------------------------------------------------------------------

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

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

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

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

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

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

    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

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

    \19\ See supra n.13.
---------------------------------------------------------------------------

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

    \20\ Transmission Relay Loadability Reliability Standard, Notice
of Proposed Rulemaking, 74 FR 35830 (Jul. 21, 2009), FERC Stats. &
Regs. ] 32,642 (2009) (NOPR).
---------------------------------------------------------------------------

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

    \21\ See, e.g., NERC Comments, EEI, TAPS, APPA, NARUC, EPSA,
Exelon.
---------------------------------------------------------------------------

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

    \22\ 16 U.S.C. 824o(d)(2).
---------------------------------------------------------------------------

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

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

    \24\ Id. P 186.
    \25\ Id.
    \26\ Id.
---------------------------------------------------------------------------

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

    \27\ Id. P 187.
---------------------------------------------------------------------------

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

Commission described this as an ``add in'' approach to
applicability.\28\
---------------------------------------------------------------------------

    \28\ NOPR, FERC Stats. & Regs. ] 32,642 at P 40.
---------------------------------------------------------------------------

    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,

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

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

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

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

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

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

    \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

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.

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

    \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.

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,

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

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

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