operational studies among planning coordinators, transmission owners,
generator owners, distribution providers, and Regional Entities. As
with our other directives in this Final Rule, we do not prescribe this
specific change as an exclusive solution to our reliability concerns
regarding sub-requirement R3.3. As we have stated, the ERO can propose
an alternative solution that it believes is an equally effective and
efficient approach to addressing the Commission's reliability
concerns.\172\
---------------------------------------------------------------------------

    \172\ Id. P 186.
---------------------------------------------------------------------------

I. Attachment A

    238. Attachment A of the Reliability Standard contains three
sections: (1) A non-exhaustive list of load-responsive relays subject
to the Standard; (2) a statement that out-of-step blocking protective
schemes are subject to the Standard and shall be evaluated to ensure
that they do not block trip for fault during the loading conditions
defined within the Standard's

requirements; and (3) a list of protective systems that are expressly
excluded from the Standard's requirements. In the NOPR, the Commission
expressed concerns about sections 2 and 3.
1. Section 2: Evaluation of Out-of-Step Blocking Schemes
    239. Section 2 of Attachment A states that the ``[Reliability
Standard] includes out-of-step blocking schemes which shall be
evaluated to ensure that they do not block trip for faults during the
loading conditions defined within the requirements.''
a. NOPR Proposal
    240. In the NOPR, the Commission stated that since the ERO intends
to require the evaluation of out-of-step blocking applications,
language to this effect should be included in PRC-023-1 as a
Requirement. To this end, the Commission proposed to direct the ERO to
add section 2 of Attachment A to PRC-023-1 as an additional Requirement
with the appropriate violation risk factor and violation severity level
assignments.
b. Comments
    241. NERC agrees that the proposed modification is appropriate and
proposes to implement it through the full Reliability Standards
development process in the next modification of PRC-023-1. In the
meantime, NERC requests that the Commission approve Attachment A as
currently written.\173\
---------------------------------------------------------------------------

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

    242. WECC asserts that the Commission's proposal is reasonable
because the obligation to evaluate out-of-step blocking schemes is part
of PRC-023-1, but carries no penalty without a violation risk factor
and violation severity level. WECC suggests that the Commission take
the same approach with respect to out-of-step tripping (section 1.2).
WECC explains that without appropriate load supervision, out-of-step
tripping may subject circuit breakers to excessive over-voltages, if it
occurs at all.
    243. Dominion, EEI, and Oncor disagree with the Commission's
proposal. Rather than make it a Requirement, Dominion argues that the
statement about out-of-step blocking schemes should be removed from
PRC-023-1 and included in a Reliability Standard that addresses stable
power swings. EEI asserts that section 2 appropriately appears in
Attachment A because Attachment A identifies the types of transmission
line relays and relay schemes that are subject to the Reliability
Standard, and out of step blocking relays are ``transmission line
relays'' addressed in Requirement R1. Oncor argues that section 2 is
already a requirement because it is in an attachment instead of an
appendix.
c. Commission Determination
    244. We adopt the NOPR proposal and direct the ERO to include
section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and
violation severity level.
    245. EEI correctly states that Attachment A is a compilation of the
types of transmission line relays and relay schemes that are subject to
PRC-023-1, and that section 2 specifies that out-of-step blocking
schemes are subject to it. However, section 2 also creates an
obligation to evaluate out-of-step blocking schemes to ensure that they
do not block trip for faults during the loading conditions defined
within the Reliability Standard's Requirements. This is an obligation
that is not stated in, or referenced by, any Requirement in the
Reliability Standard. Consequently, this obligation is not currently
associated with a violation risk factor or violation severity level.
    246. Although the obligation to evaluate out-of-step blocking
schemes is currently not stated in a Requirement, it nevertheless
remains an obligation imposed on entities by PRC-023-1 because it is a
part of Attachment A and therefore a part of PRC-023-1. Consequently,
we clarify that entities must comply with this obligation while the ERO
modifies PRC-023-1 to include it as a Requirement.
    247. We disagree with Dominion's suggestion that the Commission
direct the ERO to remove section 2 from PRC-023-1 and include it in a
Reliability Standard that addresses stable power swings. It is
appropriate to include section 2 as a Requirement in PRC-023-1 because
out-of-step blocking schemes must be allowed to trip for faults during
the loading conditions defined within PRC-023-1. Otherwise, faults that
occur during a power swing may result in system instability if not
cleared.
    248. Finally, we will not direct the ERO to make section 1.2 into a
Requirement as WECC suggests. Section 1 of Attachment A is a non-
exhaustive list of relays and protection systems that are subject to
Attachment A; unlike section 2, section 1 does not create substantive
obligations that are neither stated in nor referenced by the
Requirements. Section 1.2 merely lists out-of-step tripping systems as
one of the systems that are subject to the Reliability Standard and
must be set pursuant to Requirement R1.
2. Section 3: Protection Systems Excluded From the Reliability Standard
    249. Section 3 lists certain protection systems that are excluded
from the requirements of PRC-023-1. These systems are specified in
sections 3.1 through 3.9.
a. NOPR Proposal
    250. In the NOPR, the Commission stated that it could not determine
whether the exclusions in section 3 are justified because NERC did not
provide the technical rationale behind any of the exclusions.\174\
---------------------------------------------------------------------------

    \174\ The exclusion of protection systems intended for the
detection of ground fault conditions appears to be unnecessary
because these systems are not load-responsive.
---------------------------------------------------------------------------

    251. The Commission also raised specific concerns about section
3.1, which excludes from the Reliability Standard's requirements relay
elements that are enabled only when other relays or associated systems
fail, such as those overcurrent elements enabled only during loss of
potential conditions or elements enabled only during the loss of
communications. The Commission expressed concern that section 3.1 could
be interpreted to exclude certain protection systems that use
communications to compare current quantities and directions at both
ends of a transmission line, such as pilot wire protection or current
differential protection systems supervised by fault detector relays.
The Commission explained that if supervising fault detector relays are
not subject to the Reliability Standard, and they are set below the
rating of the protected element, the loss of communications and heavy
line loading conditions that approach the line rating would cause them
to operate and unnecessarily disconnect the line; adjacent transmission
lines with similar protection systems and settings would also operate
unnecessarily, resulting in cascading outages. The Commission requested
comments, therefore, on whether the exclusions in section 3 are
technically justified and whether it should direct the ERO to modify
PRC-023-1 by deleting specific sections in section 3. The Commission
also requested comment on whether it should direct the ERO to modify
section 3.1 to clarify that it does not exclude from the requirements
of PRC-023-1 pilot wire protection or current

differential protection systems supervised by fault detector
relays.\175\
---------------------------------------------------------------------------

    \175\ The Commission also noted that section 3.5 excludes from
the requirements of PRC-023-1 ``relay elements used only for
[s]pecial [p]rotection [s]ystems applied and approved in accordance
with NERC Reliability Standards PRC-012 through PRC-017.'' Since
PRC-012-0, PRC-013-0 and PRC-014-0 are currently proposed
Reliability Standards pending before the Commission, the particular
relay elements they involve remain subject to PRC-023-1 until the
relevant Standards are approved by the Commission. Order No. 693-A,
120 FERC ] 61,053 at P 138.
---------------------------------------------------------------------------

b. Comments
    252. While NERC acknowledges that specific justification should be
included for those protection systems that ultimately remain excluded
from the Reliability Standard's requirements, NERC opposes removing any
of the exclusions.\176\
---------------------------------------------------------------------------

    \176\ NERC Comments at 35.
---------------------------------------------------------------------------

    253. With respect to section 3.1, NERC does not share the
Commission's concern and urges it not to direct the removal of
supervising fault detector relays from the list of exclusions. NERC
explains that section 3.1 excludes elements that: (1) Do not respond to
load current; (2) are in use only during very short periods of time to
address short-term conditions; or (3) supervise operation of relay
elements that themselves are subject to the Reliability Standard. NERC
explains that if the supervised relay element itself does not operate
in these cases, the operation of the supervising element should have no
impact on reliability. NERC asserts that if a communications system is
lost, the transmission element must be protected and may need to be
tripped for low magnitude faults approaching load current. NERC argues
that it is preferable to trip one line for loss of communications than
not trip at all, thereby causing mis-coordination and/or stability
problems. NERC adds that the failure of a communications-based
protection system is typically an isolated event.
    254. EEI speculates that the intent behind specifically excluding
overcurrent elements enabled only during loss of potential conditions
and elements enabled only during a loss of communications (the specific
examples listed in section 3.1) is to exclude relay system failures
that, for normal utility practice, would result in either emergency
call outs and repairs or next-day call outs and repairs. EEI concludes
that these failures are rare enough to have a limited impact on the
Bulk-Power System.
    255. EEI and Ameren support section 3.1 as technically justified
because it allows transmission lines to remain in-service with a level
of fault protection while the failure that required activation of the
section 3.1 relays is repaired, and that the alternative would be to
take the lines or buses out of service.\177\ Ameren cautions that this
alternative would put the system in a less reliable N-1 or N-many
state.
---------------------------------------------------------------------------

    \177\ EEI at 27-28; Ameren at 15.
---------------------------------------------------------------------------

    256. EEI adds that many long transmission lines proposed to support
the creation of the national grid will require backup protection for
the types of failures discussed in section 3.1. EEI explains that, for
very long lines, the fault currents can be below rated continuous
capability without the 150 percent margin, and that simple schemes are
required for the small periods of time when the backup protection will
be in-service following a loss of potential conditions or
communications. EEI contends that these exceptions only impact one
facility at a time and do not present more risk than removing the
facility.
    257. Exelon, Consumers Energy, and IESO/Hydro One also claim that
the exclusions in section 3.1 are justified. Exelon asserts that the
Reliability Standard's goal is to address protective relays that have a
history of contributing to cascades, and that relays enabled only when
other relays or associated systems fail are extremely unlikely to be a
factor in a disturbance because they are enabled so infrequently.
Consumers Energy cautions that the relays excluded in section 3.1 must
be able to respond to relay failures without regard to relay
loadability; otherwise, there is a risk that faults will not be cleared
and there will be cascading outages. IESO/Hydro One argue that the
Commission should approve section 3.1 because the relays it excludes
are incapable of independently opening the circuit breaker; that is,
they require the action of other relays.
    258. TAPS argues that NERC should reconsider section 3.1 because
the exclusion of relay elements enabled only when other relays or
associated systems fail depends on the successful operation of a
potential source (potential transformer or capacitor coupled voltage
transformer (CCVT)) or a communication system.\178\ TAPS explains that
the TPL Reliability Standards require planners to plan the system as if
a potential source or communication system has failed (e.g., TPL-003-
0). Although potential sources and communication systems fail
infrequently, TAPS states that it might be consistent with the TPL
Standards for NERC to reconsider the balance of these factors. TAPS
argues, however, that the Commission should not require NERC to
eliminate section 3.1.
---------------------------------------------------------------------------

    \178\ TAPS, Attachment 1 at 17.
---------------------------------------------------------------------------

    259. In general, commenters contend that the rest of the exclusions
in section 3 have a sound technical basis. Basin argues that the
exclusions address protection systems that have no significant impact
on the reliability of the bulk electric system, and suggests that the
Commission consider the following criteria in determining whether a
system should be subject to PRC-023-1: (1) The frequency with which
that system is enabled; (2) the probability that the system will be
activated when it is enabled; and (3) the effects that the protection
system will have on the Bulk-Power System when it is activated.\179\
Basin argues that protection systems that have a low probability of
being activated when enabled should be excluded from the Reliability
Standard. Likewise, those that, when activated, have an inconsequential
effect on system stability should also be excluded from the Reliability
Standard. The PSEG Companies argue that PRC-023-1 reasonably balances
risks with the potential expenditure of substantial and costly changes
to protection systems.\180\
---------------------------------------------------------------------------

    \179\ Basin at 12-13.
    \180\ PSEG Companies at 12.
---------------------------------------------------------------------------

    260. Exelon and Consumers Energy argue that section 3.2, which
excludes relays that are designed to detect ground fault conditions, is
justified because such relays have no significant history of
contributing to cascades. Consumers Energy claims that it would be a
waste of resources to identify, study, and document the behavior of
devices intended for the detection of ground faults, when such devices
are immune to tripping for load currents.
    261. Duke asserts that it is unclear whether section 3.3, which
excludes protection systems intended for protection during stable power
swings, is meant for tripping or to block tripping. Duke states that if
the protection is to block tripping, the exclusion is in conflict with
section 2 of Attachment A, as many relays use the same logic to block
for out-of-step conditions and for stable power swings.
    262. Exelon states that the relays identified in section 3.5, which
excludes relays used for special protection systems applied and
approved in accordance with Reliability Standards PRC-012 through PRC-
017, are designed along with specific relay settings to assure that a
given power system meets NERC performance requirements. Consumers
Energy asserts that these relay systems are intended for a specific set
of conditions and already

undergo a stringent review, such that additional review under PRC-023-1
is unnecessary and creates the risk that a special protection system
approved under PRC-012 through PRC-017 may be found non-compliant under
PRC-023-1. Dominion adds that relay elements used only for special
protection systems applied and approved in accordance with PRC-012
through PRC-017 do not present a risk to the reliability of the grid
because the instances in which they operate are rare events that are
addressed and corrected in a timely manner.\181\
---------------------------------------------------------------------------

    \181\ Dominion at 8.
---------------------------------------------------------------------------

    263. TAPS argues that the exclusions in sections 3.2 through 3.8
are designed to ensure that PRC-023-1 applies where it is needed to
address loadability concerns, but does not interfere with relays that
are not tripped by load current. TAPS adds that section 3.9, which
excludes relay elements associated with DC converter transformers, is
justified because the output of generators and DC line converters is
not changed significantly with the loss of other facilities.\182\
---------------------------------------------------------------------------

    \182\ TAPS at 27-28.
---------------------------------------------------------------------------

c. Commission Determination
    264. After further consideration, and in light of the comments, we
will not direct the ERO to remove any exclusion from section 3, except
for the exclusion of supervising relay elements in section 3.1.
Consequently, we direct the ERO to revise section 1 of Attachment A to
include supervising relay elements on the list of relays and protection
systems that are specifically subject to the Reliability Standard. As
with our other directives in this Final Rule, we do not prescribe this
specific change as an exclusive solution to our reliability concerns
regarding the exclusion of supervising relay elements. As we have
stated, the ERO can propose an alternative solution that it believes is
an equally effective and efficient approach to addressing the
Commission's reliability concerns.\183\
---------------------------------------------------------------------------

    \183\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 186.
---------------------------------------------------------------------------

    265. Supervising elements ensure that a protection system is secure
and does not operate when it should not operate. When a supervising
relay is in place, it acts as a check on the supervised protection
system because both must operate to trip a facility. If a supervising
relay is set below the rating of the line, high loading conditions will
cause it to be ``picked-up,'' i.e., continuously energized and ready to
operate. When this occurs, the supervising relay will no longer be able
to act as a check on the other protection system because the
supervising relay will already have registered that it should operate.
At that point, the supervising relay will be waiting for the supervised
relay to become energized before tripping the protected facility.\184\
---------------------------------------------------------------------------

    \184\ It works like an ``and'' condition (0 + 0 = no trip line,
1 + 1 = trip line, 1 + 0 = no trip line). For a supervising relay
like a fault detector to be always ``picked up'' means that the
relay is energized (it is always a ``1'') and is waiting for another
relay to also become energized before tripping a facility.
---------------------------------------------------------------------------

    266. For example, current differential protection systems use
communication systems to transmit and compare information between
relays located at both terminals and to initiate the high-speed
tripping of a facility when the difference of currents at the sending
end and receiving end exceeds a threshold setting usually set at a
small fraction of the normal line loading. Since these protection
systems are dependent on communication systems, the protected facility
will trip if communication is lost, even when the line continues to
carry its normal load current, because the difference of the currents
as seen at either end will be the load current which is much larger
than the threshold setting. Consequently, overcurrent relays are
typically used as supervising relays to prevent the protected facility
from tripping if communication is lost. However, if the supervising
relays are energized due to loading conditions, and then communication
is lost, the current differential protection system will operate in the
absence of a fault and the protected facility will trip.
    267. NERC asserts that it is preferable to trip one line for loss
of communications than not trip at all, thereby causing mis-
coordination and/or stability problems. We disagree. Protective relays
should not operate during non-fault conditions. The tripping of
facilities for non-fault conditions, like NERC describes, or in the
case of the August 2003 blackout is not desirable system performance.
    268. We also disagree with IESO/Hydro One's assertion that the
exclusion of supervising relays from PRC-023-1 is appropriate because
such relays are not capable of independently opening the circuit
breaker. While a supervising relay is not designed to independently
trip a facility by initiating the opening of the circuit breaker, if
that relay is picked up and energized during non-fault conditions, it
is no longer capable of ensuring the security of a protection system
and may result in the unnecessary tripping of the facility it is
protecting. As we explained, if supervising relays are not subject to
the Reliability Standard, and are set below the rating of the protected
element, the loss of communications and heavy line loading conditions
that approach the line rating would cause them to operate and
unnecessarily disconnect the line.\185\ A more recent example is an
event that occurred on June 27, 2007 where 138 kV transmission lines in
the NPCC region resulted in sequential tripping of the four 138 kV
cable-circuits. The event resulted in the interruption of service to
about 137,000 customers as well as the loss of five generators and six
138 kV transmission lines. This event is the type of situation that
PRC-023-1 is intended to prevent, and illustrates why we must direct
the ERO to modify Attachment A to include supervising relays.
---------------------------------------------------------------------------

    \185\ NOPR, FERC Stats. & Regs. ] 32,642 at P 79.
---------------------------------------------------------------------------

    269. Although we do not direct the ERO to remove section 3.1 from
the list of excluded protection systems, we find it necessary to
address some comments made in the context of the Commission's proposal.
For example, we disagree with those commenters that suggest that the
Commission should approve section 3.1 because it excludes from the
Reliability Standard's scope relays and protection systems that rarely
operate. These commenters appear to suggest that protection systems
that rarely operate do not pose a risk to the reliability of the Bulk-
Power System. We disagree. A protective relay, as an integral part of
the Bulk-Power System, must be dependable and secure; it must operate
correctly when required to clear a fault and refrain from operating
unnecessarily, i.e., during non-fault conditions or for faults outside
of its zone of protection, regardless of how many times the relay must
actually operate.\186\ Relays must meet this expectation to contribute
to ensuring Reliable Operation of the Bulk-Power System. Consequently,
the notion that any specific relay should be excluded from the
Reliability Standard's scope because it may operate only on rare
occasions is inconsistent with the fundamental principles that make
protective relays an integral part of ensuring Reliable Operation.
---------------------------------------------------------------------------

    \186\ These fundamental objectives for protection systems are
consistent if not identical with the ones stated in NERC Planning
Standards III: System Protection and Control, at 43: Dependability--
a measure of certainty to operate when required, Security--a measure
of certainty not to operate falsely.
---------------------------------------------------------------------------

    270. We also disagree with Ameren's assertion that removing section
3.1 from the list of exclusions would put the Bulk-Power System in a
``less reliable N-1state.'' As we discuss above, if supervising relays
that are used in

current differential schemes are excluded from PRC-023-1 and set much
below the line rating, they will trip the protected lines inadvertently
following the loss of communication system forming part of the
protection system.
    271. Finally, Duke asserts that section 3.3 is ambiguous with
respect to whether it excludes protection meant for tripping or to
block tripping, and that if it excludes protection meant to block
tripping, it is in conflict with section 2 because many relays use the
same logic to block for out-of-step conditions and for stable power
swings. We clarify that we do not find a conflict between section 3.3,
which excludes from the Reliability Standard's scope any protection
system intended for protection during stable power swings, and section
2, which ensures that out-of-step blocking schemes do not block
tripping during the loading conditions defined within PRC-023-1.
    272. Out-of-step schemes, blocking and tripping, are generally
associated with power swing protection applications. Out-of-step
tripping schemes allow controlled tripping during loss of synchronism
during unstable power swings while out-of-step blocking schemes block
tripping during stable power swings. Because out-of-step tripping
relays are supervised by load-responsive overcurrent relays, its
applicability to the requirements of PRC-023-1 is appropriate. Because
the reliability objective of Requirement R1 is to set protective relays
while ``maintaining reliable protection of the bulk-electric system for
all fault conditions,'' as previously determined, out-of-step blocking
schemes must allow tripping for faults during the loading conditions
defined within PRC-023-1. Thus, the reliability goal of the two schemes
for the purposes of PRC-023-1 is different, and consequently, we find
no conflict within the Standard.

J. Effective Date

    273. NERC proposed the following effective dates for Requirements
R1 and R2: (1) The beginning of the first calendar quarter following
applicable regulatory approvals for all transmission lines and
transformers with low-voltage terminals operated/connected at and above
200 kV, except for switch-on-to fault-schemes; (2) the beginning of the
first calendar quarter 39 months after applicable regulatory approvals
for all transmission lines and transformers with low-voltage terminals
operated/connected between 100 kV and 200 kV, including switch-on-to
fault-schemes; \187\ and (3) 24 months from notification by the
planning coordinator that, pursuant to the ``add in'' approach, a
facility has been added to the planning coordinator's list of critical
facilities. For Requirement R3, NERC proposed an effective date of 18
months following applicable regulatory approvals.
---------------------------------------------------------------------------

    \187\ ``Switch-on-to-fault schemes'' are protection systems
designed to trip a transmission line breaker when the breaker is
closed into a fault. Because the current fault detectors for these
systems must be set low enough to detect ``zero-voltage'' faults,
i.e., close-in, three-phase faults, these systems may be susceptible
to operate on load.
---------------------------------------------------------------------------

    274. NERC also proposed to include a footnote (exceptions footnote)
to the ``Effective Dates'' section honoring temporary exceptions from
enforcement actions approved by the NERC Planning Committee before NERC
proposed the Reliability Standard.\188\
---------------------------------------------------------------------------

    \188\ The footnote states:
    Temporary Exceptions that have already been approved by the NERC
Planning Committee via the NERC System and Protection and Control
Task Force prior to the approval of this [Reliability Standard]
shall not result in either findings of non-compliance or sanctions
if all of the following apply: (1) The approved requests for
Temporary Exceptions include a mitigation plan (including schedule)
to come into full compliance, and (2) the non-conforming relay
settings are mitigated according to the approved mitigation plan.
---------------------------------------------------------------------------

1. NOPR Proposal
    275. In the NOPR, the Commission proposed to approve NERC's
implementation plan for facilities operated at and above 200 kV. In
light of its applicability proposals, the Commission proposed to reject
the rest of NERC's implementation plan and require, for all sub-200 kV
facilities, an effective date of 18 months following applicable
regulatory approvals. The Commission also proposed to direct NERC to
remove the exceptions footnote, explaining that discussions about
potential enforcement actions are best left out of a Reliability
Standard and instead handled by NERC's compliance and enforcement
program.\189\
---------------------------------------------------------------------------

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

2. Comments on Effective Date Proposals
    276. In general, commenters support the Commission's proposal to
adopt the effective date proposed by NERC for facilities operated at
and above 200 kV, but overwhelmingly oppose the Commission's proposal
for an 18 month effective date for sub-200 kV facilities, regardless of
whether the Commission directs the ERO to adopt the ``rule out''
approach or approves NERC's ``add in'' approach.\190\ Commenters
generally argue that the Commission should adopt NERC's proposal of an
effective date of the beginning of the first calendar quarter 39 months
after applicable regulatory approvals for 100 kV-200 kV facilities.
---------------------------------------------------------------------------

    \190\ Commenters argue that a ``rule out'' approach would
require a much longer implementation period, with estimates of up to
12 years.
---------------------------------------------------------------------------

    277. NERC argues that planning coordinators will require at least
18 months to identify the 100 kV-200 kV facilities that should be
subject to the Reliability Standard, and possibly an additional 18 to
24 months to complete any design and construction changes necessary to
comply with the Standard. Consumers Energy, EEI, and Oncor offer
similar estimates.
    278. APPA argues that NERC's implementation plan gives planning
coordinators the time necessary to perform in-depth studies to identify
which facilities are critical to the reliability of the bulk electric
system, and gives affected entities the time to make any necessary
costly upgrades. APPA adds that only a limited number of experienced
industry experts and consultants will be available to assist entities
in complying with the Reliability Standard, and speculates that their
time will be in high demand.
    279. TAPS observes that Order No. 672 recognizes that
implementation timelines must balance any urgency in the need to
implement a Reliability Standard with the reasonableness of the time
allowed for those who must comply to develop the necessary procedures,
software, facilities, staffing or other relevant capability.\191\ TAPS
argues that the Commission should give due weight to NERC's expert
assessment of that balance and adopt the effective dates proposed by
NERC.
---------------------------------------------------------------------------

    \191\ TAPS at 29 (citing Order No. 672, FERC Stats. & Regs. ]
31,204 at P 333).
---------------------------------------------------------------------------

3. Comments on Exceptions Footnote
    280. EEI argues that the Commission's proposal to direct the ERO to
remove the exceptions footnote is too prescriptive given the
Commission's statutory role in the Reliability Standard development
process. EEI argues that the Commission has gone much farther than
identifying its concern because its proposal does not allow for the ERO
to develop equally effective alternatives.\192\
---------------------------------------------------------------------------

    \192\ EEI at 28.
---------------------------------------------------------------------------

    281. Oncor and Consumers Energy agree with the Commission's
proposal. Oncor argues that the need for the temporary exemption has
expired and therefore should be removed from the Reliability Standard.

4. Commission Determination
    282. We decline to fully adopt the NOPR proposal and approve all of
NERC's proposed effective dates, including its proposal of 39 months
from the beginning of the first calendar quarter after applicable
regulatory approvals for 100 kV-200 kV facilities. In light of our
decision to approve the ``add in'' approach for 100 kV-200 kV
facilities, and after consideration of the comments, we agree with NERC
that this is an appropriate effective date.
    283. Additionally, in light of our directive to the ERO to expand
the Reliability Standard's scope to include sub-100 kV facilities that
Regional Entities have already identified as necessary to the
reliability of the Bulk-Power System through inclusion in the
Compliance Registry, we direct the ERO to modify the Reliability
Standard to include an implementation plan for sub-100 kV facilities.
    284. We also direct the ERO to remove the exceptions footnote from
the ``Effective Dates'' section. As the Commission stated in the NOPR,
the exceptions footnote is addressed to potential enforcement actions,
and is therefore best left out of the Reliability Standard and
addressed in NERC's compliance and enforcement program. Moreover, we
agree with Oncor that the need for the temporary exemption has expired
and therefore should be removed from the Reliability Standard. We add
that entities are free to request exceptions through NERC's existing
process, subject to Commission review and approval.

K. Violation Risk Factors

    285. Requirement R1 directs entities to set their relays according
to one of the options set forth in sub-requirements R1.1 through R1.13.
NERC assigned Requirement R1 a ``high'' violation risk factor, but did
not assign violation risk factors to sub-requirements R1.1 through
R1.13.
    286. Requirement R2 provides that entities that set their relays
according to sub-requirements R1.6 through R1.9, R1.12, or R1.13 must
use the calculated circuit capability as the circuit's facility rating
and must obtain the agreement of the planning coordinator, transmission
operator, and reliability coordinator as to the calculated circuit
capability. NERC assigned Requirement R2 a ``medium'' violation risk
factor.
    287. Requirement R3 requires planning coordinators to determine
which sub-200 kV facilities are critical to the reliability of the bulk
electric system and therefore subject to Requirement R1.\193\ NERC
assigned Requirement R3 a ``medium'' violation risk factor.
---------------------------------------------------------------------------

    \193\ As proposed by NERC, Requirement R3 directs planning
coordinators to identify the 100 kV-200 kV facilities that should be
subject to Requirement R1. As we have explained, in this Final Rule
we direct that the ERO revise Requirement R3 so that planning
coordinators also identify sub-100 kV facilities that should be
subject to the Reliability Standard.
---------------------------------------------------------------------------

1. NOPR Proposal
    288. In the NOPR, the Commission listed the five guidelines that it
uses to evaluate proposed violation risk factor assignments (Violation
Risk Factor Guidelines). According to these Guidelines, violation risk
factor assignments should be consistent: (1) With the conclusions of
the Final Blackout Report; (2) within a Reliability Standard; (3) among
Reliability Standards with similar Requirements; and (4) with NERC's
definition of the violation risk factor level; the Commission also
stated that (5) the violation risk factor levels for Requirements that
co-mingle a higher risk reliability objective and a lower risk
reliability objective must not be watered down to reflect the lower
risk level associated with the less important reliability
objective.\194\
---------------------------------------------------------------------------

    \194\ NOPR, FERC Stats. & Regs. ] 32,642 at P 88. For a complete
discussion of each guideline, see North American Electric
Reliability Corp., 119 FERC ] 61,145, P 19-36 (Violation Risk Factor
Order), order on reh'g and compliance filing, 120 FERC ] 61,145
(2007) (Violation Risk Factor Rehearing Order).
---------------------------------------------------------------------------

    289. The Commission agreed with NERC that Requirement R1 should be
assigned a ``high'' violation risk factor. The Commission added,
however, that violation of any of the criteria in sub-requirements R1.1
through R1.13 present the same reliability risk as a violation of
Requirement R1 because they set forth the options for compliance with
Requirement R1. Consequently, the Commission proposed to direct the ERO
to assign a ``high'' violation risk factor to each sub-requirement.
    290. The Commission also proposed to direct the ERO to modify the
violation risk factor assigned to Requirement R3 and its sub-
requirements to reflect the Commission's applicability proposals.
2. Comments
    291. NERC and other commenters oppose the Commission's proposal to
assign a separate violation risk factor to sub-requirements R1.1
through R1.13. These commenters argue that the sub-requirements are
alternative ways to comply with Requirement R1, not separate
Requirements that must be complied with in their own right. The
commenters point out that each sub-requirement is intended to address a
different operating condition or system design condition and that, for
any specific circuit, entities will set their relays pursuant to only
one of the sub-requirements. NERC adds that its proposal to assign
violation risk factors only to Requirement R1 is consistent with its
informational filing in Docket No. RM08-11-000, where it described more
fully its plans for a new, comprehensive approach to assigning
violation risk factors.\195\
---------------------------------------------------------------------------

    \195\ In its informational filing, NERC indicates that NERC
drafting teams will develop ``rolled up'' violation risk factors and
violation severity levels.
---------------------------------------------------------------------------

    292. An individual commenter, Michael McDonald, argues that
Requirement R1 should have a ``medium'' violation risk factor, rather
than a ``high'' violation risk factor, because actions taken since the
August 2003 blackout have reduced the likelihood that a relay
loadability issue will cause a cascading outage.
3. Commission Determination
    293. We approve NERC's assignment of a ``high'' violation risk
factor to Requirement R1 and a ``medium'' violation risk factor to
Requirement R2. These violation risk factor assignments are consistent
with the Violation Risk Factor Guidelines.
    294. We disagree with Michael McDonald, who argues that Requirement
R1 should have a ``medium'' violation risk factor rather than a
``high'' violation risk factor. Violation risk factor assignments
represent the risk a violation of a Requirement presents to the Bulk-
Power System.\196\ Although the Commission, the ERO, and industry have
taken actions since the August 2003 blackout to reduce the likelihood
that relay outages will cause cascading outages, these actions do not
mitigate the risk of non-compliance with Requirement R1. In our view, a
violation of Requirement R1 has the potential to put the Bulk-Power
System at the risk of cascading outages like those that occurred during
the August 2003 blackout. Consequently, we agree with the ERO that
Requirement R1 should be assigned a ``high'' violation risk factor.
---------------------------------------------------------------------------

    \196\ North American Electric Reliability Corp., 121 FERC ]
61,179, at P 38 (2007).
---------------------------------------------------------------------------

    295. We will not require the ERO to assign a violation risk factor
to each sub-requirement of Requirement R1 because we agree with the ERO
that the sub-requirements are alternative ways, based on different
operating or design configurations, of complying with Requirement R1.
Consequently, an entity's failure to appropriately apply

one of the sub-requirements of Requirement R1 to a specific operating
design or configuration is, as a violation of Requirement R1, subject
to a ``high'' violation risk factor. While the Commission generally
expects that the ERO will assign a violation risk factor to each
Requirement and sub-requirement of a Reliability Standard, we will
accept the ERO's proposal not to assign violation risk factors to sub-
requirements R1.1 through R1.13 as an exception to our current policy
because we are satisfied that the sub-requirements do not constitute
independent compliance requirements separate from Requirement R1.\197\
---------------------------------------------------------------------------

    \197\ NERC's assignment of violation risk factors in Reliability
Standard PRC-023-1 appears to be consistent with the approach to
assigning violation risk factors set forth in NERC's informational
filing in Docket No. RM08-11-000. At NERC's request, the Commission
has not acted on the informational filing. The Commission
understands, however, that NERC anticipates formally filing a
comprehensive ``roll up'' plan in the second quarter of 2010.
Consequently, we direct the ERO to re-file the violation risk
factors associated with the Requirements of PRC-023-1 when it
submits its comprehensive plan.
---------------------------------------------------------------------------

    296. We also agree with the ERO's decision to assign Requirement R2
a ``medium'' violation risk factor. Requirement R2 comprises two
reliability obligations: (1) The required use of the calculated circuit
capability as the facility rating of the circuit for entities that set
their relays according to sub-requirements R1.6 through R1.9, R1.12, or
R1.13; and (2) the entities' obligation to obtain the agreement of the
planning coordinator, transmission operator, and reliability
coordinator as to the calculated circuit capability. Requirement R2 co-
mingles more than one reliability obligation and, consistent with
Violation Risk Factor Guideline 5, the assigned violation risk factor
reflects the reliability risk of a violation of the higher reliability
obligation (i.e., the requirement to use the calculated circuit
capability as the facility rating of the circuit).
    297. Finally, we direct the ERO to assign a ``high'' violation risk
factor to Requirement R3. The Commission expects consistency between
violation risk factors assigned to Requirements that address similar
reliability goals.\198\ NERC assigned a ``high'' violation risk factor
to Requirement R1, which requires entities to set their relays
according to one of the criteria in sub-requirements R1.1 through
R1.13. Requirement R3 directs planning coordinators to determine which
sub-200 kV facilities will be subject to Requirement R1. Since the
facilities identified by the planning coordinator pursuant to
Requirement R3 are required to meet Requirement R1, we conclude that
the reliability risk to the Bulk-Power System of a violation of
Requirement R3 is the same as a violation of Requirement R1. We direct
the ERO to file the new violation risk factor no later than 30 days
after the date of this Final Rule.
---------------------------------------------------------------------------

    \198\ Violation Risk Factor Order, 119 FERC ] 61,145 at P 25.
---------------------------------------------------------------------------

L. Violation Severity Levels

    298. NERC proposed violation severity levels for Requirements R1,
R2, and R3, but not for sub-requirements R1.1 through R1.13 or R3.1
through R3.3.
    299. For Requirement R1, NERC proposed: (1) A ``moderate''
violation severity level when an entity complies with a sub-requirement
of Requirement R1, but has incomplete or incorrect evidence of
compliance; and (2) a ``severe'' violation severity level when an
entity fails to comply with a sub-requirement of Requirement R1, or
when the entity lacks any evidence of compliance.
    300. NERC designated Requirement R2 as a ``binary'' Requirement and
proposed a ``lower'' violation severity level when an entity sets its
relays pursuant to sub-requirements R1.6 through R1.9, R1.12, or R1.13,
but lacks evidence that it obtained the agreement of the planning
coordinator, transmission operator, and reliability coordinator as to
the calculated circuit capability.\199\
---------------------------------------------------------------------------

    \199\ ``Binary'' Requirements are Requirements where compliance
is defined in terms of ``pass'' or ``fail.''
---------------------------------------------------------------------------

    301. For Requirement R3, NERC proposed: (1) A ``severe'' violation
severity level when an entity lacks a process to identify critical
facilities; and (2) ``moderate'' and ``high'' violation severity levels
based on the number of days that a planning coordinator is late in
providing the critical facilities list to the entities that must
receive it.
1. NOPR Proposal
    302. In the NOPR, the Commission listed the four guidelines that it
uses to evaluate proposed violation severity levels (Violation Severity
Level Guidelines).\200\ According to these Guidelines, violation
severity levels should: (1) Avoid the unintended consequence of
lowering the current level of compliance; (2) ensure uniformity and
consistency among all approved Reliability Standards in the
determination of penalties; \201\ (3) be consistent with the
corresponding Requirement; and (4) be based on a single violation, not
on a cumulative number of violations.
---------------------------------------------------------------------------

    \200\ For a complete discussion of each guideline, see North
American Electric Reliability Corporation, 123 FERC ] 61,284, at P
19-36 (Violation Severity Level Order), order on reh'g and
compliance filing, 125 FERC ] 61,212 (2008) (Violation Severity
Level Rehearing Order).
    \201\ In the Violation Severity Level Order, the Commission
identified two specific concerns with the uniformity and consistency
of the violation severity level assignments then under review: (a)
The single violation severity levels assigned to individual binary
requirements were not consistent; and (b) the violation severity
level assignments contained ambiguous language. With respect to
concern identified in (a), which the Commission referred to as
``Guideline 2a,'' the Commission explained that NERC assigned
different violation severity levels to different binary Requirements
(i.e. pass/fail Requirements) without justifying the different
assignments or explaining how they were consistent with the
application of a basic pass/fail test. The Commission directed NERC
to modify the violation severity levels by either: (1) Consistently
applying the same severity level to each binary Requirement; or (2)
changing from a binary approach to a gradated approach. Violation
Severity Level Order 123 FERC ] 61,284 at P 23-27, 45-47. In its
compliance filing, NERC chose the first option and proposed to apply
a ``severe'' violation severity level to each of the binary
Requirements. The Commission agreed with this approach. North
American Electric Reliability Corporation, 127 FERC ] 61,293, at P
5, 11 (2009).
---------------------------------------------------------------------------

    303. The Commission observed that the violation severity levels
assigned to Requirements R1 and R2 appear to be inconsistent with
Violation Severity Level Guideline 3. The Commission noted that the two
violation severity levels proposed for Requirement R1 address both: (1)
The severity of a violation (i.e., the fact that relay settings do not
comply with Requirement R1); and (2) facts necessarily associated with
evaluating compliance (i.e., the existence of evidence that relay
settings comply with Requirement R1). The Commission explained that
Requirement R1 does not require evidence of compliance, only
compliance. Similarly, the Commission stated that the single violation
severity level proposed for Requirement R2 does not reflect the
severity of a violation of Requirement R2, but the severity of lacking
evidence of compliance with Requirement R2. Consequently, the
Commission proposed to direct the ERO to: (1) Adopt a binary approach
to Requirement R1; i.e., assign a violation severity level based on
whether or not the entity complies with Requirement R1; and (2) assign
a violation severity level for Requirement R2 that addresses an
entity's failure to comply with the entire Requirement; i.e., its
failure to calculate circuit capability as the facility rating and
obtain agreement on that rating with the required entities. The
Commission also proposed to direct the ERO to assign a single violation
severity level to each sub-requirement in Requirement R1.

    304. The Commission also stated that the single violation severity
level assigned to Requirement R2 appears to be inconsistent with NERC's
Guideline 2a compliance filing in Docket No. RR08-4-004.\202\ The
Commission explained that, in that docket, NERC assigned ``severe''
violation severity levels to binary Requirements. The Commission added
that it expects the violation severity levels assigned to binary
requirements to be consistent, and proposed to direct the ERO to revise
the violation severity level assigned to Requirement R2 to be
consistent with Guideline 2a.
---------------------------------------------------------------------------

    \202\ See supra n. 202.
---------------------------------------------------------------------------

    305. Finally, in light of its proposals to direct the ERO to modify
Requirement R3 and its sub-requirements, the Commission proposed to
direct the ERO to assign new violation severity levels to Requirement
R3 and its sub-requirements, consistent with the Violation Severity
Level Guidelines.
2. Comments
    306. NERC agrees with the Commission's proposal to review the
violation severity levels in accordance with the Violation Severity
Level Guidelines.\203\ Other commenters oppose the Commission's
proposal to assign a violation severity level to each sub-requirement
in Requirement R1 for the same reasons that they oppose assigning a
violation risk factor to each sub-requirement in Requirement R1.
---------------------------------------------------------------------------

    \203\ NERC Comments at 40.
---------------------------------------------------------------------------

    307. Consumers Energy makes the general argument that ``evidence''
should be included in Requirements only when the compliance monitor
(e.g., the Regional Entity or NERC) uses it for a reliability purpose.
Consumers Energy argues that if evidence is used only to determine
whether an entity is in compliance with a Reliability Standard, the
evidence should be instead represented in a Measure as reflected in
PRC-023-1.
3. Commission Determination
    308. We adopt the NOPR proposals with respect to the violation
severity levels assigned to Requirements R1 and R2. As we explained in
the NOPR, the violation severity levels assigned to Requirement R1 are
inconsistent with Violation Severity Guideline 3 because they are based
in part on the amount of evidence of compliance that an entity can
produce, even though Requirement R1 does not require entities to have
evidence of compliance. Consequently, we direct the ERO to assign a
single violation severity level of ``severe'' for violations of
Requirement R1.
    309. While we adopt the NOPR proposal with respect to Requirement
R1, we do not adopt the NOPR proposal to direct the ERO to assign
individual violation severity levels to the sub-requirements of
Requirement R1. As we explained with respect to the violation risk
factors, we will make an exception to our general policy because we are
satisfied that the sub-requirements of Requirement R1 do not constitute
independent compliance requirements separate from Requirement R1.\204\
---------------------------------------------------------------------------

    \204\ Consistent with our treatment of violation risk factors,
we direct the ERO to re-file the violation severity factors
associated with the Requirements of PRC-023-1 when it submits its
comprehensive plan.
---------------------------------------------------------------------------

    310. We also adopt the NOPR proposal with respect to the violation
severity level assigned to Requirement R2. As the Commission pointed
out in the NOPR, the single violation severity level assigned to
Requirement R2 suffers from the same problem as the two violation
severity levels assigned to Requirement R1; namely, it is based in part
on whether an entity has evidence of compliance with the Requirement,
even though the Requirement itself does not require an entity to have
evidence of compliance. Additionally, Requirement R2 is a binary
Requirement, and NERC's assignment of a ``lower'' violation severity
level rather than a ``severe'' violation severity level is inconsistent
with its Guideline 2a compliance filing in Docket No. RR08-4-004. In
that filing, NERC assigned a ``severe'' violation severity level to
binary Requirements. As the Commission stated when discussing Guideline
2a in the Violation Severity Level Order, single violation severity
levels assigned to binary requirements should be consistent.
Accordingly, we direct the ERO to change the violation severity level
assigned to Requirement R2 from ``lower'' to ``severe'' to be
consistent with Guideline 2a.
    311. Finally, we direct the ERO to assign a ``severe'' violation
severity level to Requirement R3. Requirement R3 directs planning
coordinators to identify the critical sub-200 kV facilities that are
subject to the Reliability Standard. Similar to our determination for
Requirement R2, it is our view that Requirement R3 is a binary
requirement; either the planning coordinator identified critical
facilities or it did not. Consequently, we find that Requirement R3
must have a single violation severity level of ``severe.''
    312. We direct the ERO to file the new violation severity levels
described in our discussion no later than 30 days after the date of
this Final Rule.

M. Miscellaneous

1. Purpose of the Reliability Standard
    313. The Reliability Standard's stated purpose is to ``require[]
certain transmission owners, generator owners, and distribution
providers to set protective relays according to specific criteria in
order to ensure that the relays reliably detect and protect the
electric network from all fault conditions, but do not limit
transmission loadability or interfere with system operators' ability to
protect system reliability.''
a. Comments
    314. BPA argues that the Commission should direct the ERO to revise
the Reliability Standard's stated purpose because the Standard requires
only that certain protective relays refrain from operating during
permissible load conditions and does not require that protective relays
reliably detect and protect the electric network from all fault
conditions. BPA asserts that sub-requirement R1.12 touches on the
subject of adequately detecting faults by allowing the loadability
requirements of relay settings to be relaxed in order to allow adequate
protection, but adds that neither sub-requirement R1.12 nor any other
sub-requirement requires relays to be set to reliably detect ``all''
fault conditions and protect the electrical network from these faults.
BPA argues that the class of relays covered by the Reliability Standard
is not even capable of detecting ``all'' fault conditions. BPA
requests, therefore, that the Commission direct the ERO to revise the
Reliability Standard's stated purpose to be: ``[t]o prevent certain
protective relays from operating under permissible transmission line
and equipment loads.'' \205\
---------------------------------------------------------------------------

    \205\ BPA at 1-2.
---------------------------------------------------------------------------

b. Commission Determination
    315. We disagree with BPA. Requirement R1 directs entities to set
their relays according to one of its sub-requirements (R1.1 through
R1.13), based on their transmission configurations. No matter what
setting entities choose, they are required to apply it while
``maintaining reliable protection of the bulk electric system for all
fault conditions.'' Thus, any sub-requirement that an entity implements
must protect the electric network from all fault conditions.

2. Transmission Facility Design Margin
a. Comments
    316. Basin interprets the Commission's statement in the NOPR that
``[s]ub-requirement R1.1 specifies transmission line relay settings
based on the highest seasonal facility rating using the 4-hour thermal
rating of a line, plus a design margin of 150 percent'' to suggest that
the Commission incorrectly assumed that relay margins include an
additional transmission facility design margin, and that additional
Total Transfer Capability (TTC) can be achieved with different relay
settings. Basin states that relay operations do not affect the
calculation of TTC because relay settings are established above the
level of standard operation of the system and will not operate when
facilities are loaded at their maximum ratings.
    b. Commission Determination
    317. We clarify that the Commission did not assume that ``design
margin,'' as it is used in the context of the Reliability Standard,
equates to additional TTC on the transmission facility. The statement
in the NOPR that Basin refers to is a direct quote from NERC where NERC
describes ``design margin'' in the context of the margin (percentage)
over the 4-hour facility rating protective relay setting criteria for
sub-requirement R1.1.\206\ The ``design margin'' described in this
requirement is different than the ``transmission reliability margin''
that accounts for the inherent uncertainty in bulk electric system
conditions in the calculation of TTC established in the Modeling, Data,
and Analysis (MOD) Reliability Standards.
---------------------------------------------------------------------------

    \206\ NERC Petition at 9.
---------------------------------------------------------------------------

IV. Information Collection Statement

    318. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\207\ The information collection
requirements in this Final Rule are identified under the Commission
data collection, FERC-725G ``Transmission Relay Loadability Mandatory
Reliability Standard for the Bulk Power System.'' Under section 3507(d)
of the Paperwork Reduction Act of 1995,\208\ the proposed reporting
requirements in the subject rulemaking will be submitted to OMB for
review. Interested persons may obtain information on the reporting
requirements by contacting the Federal Energy Regulatory Commission,
888 First Street, NE., Washington, DC 20426 (Attention: Michael Miller,
Office of the Executive Director,<PHONE_NUMBER>) or from the Office of
Management and Budget (Attention: Desk Officer for the Federal Energy
Regulatory Commission, fax:<PHONE_NUMBER>, e-mail: oira_
submission@omb.eop.gov).
---------------------------------------------------------------------------

    \207\ 5 CFR 1320.11.
    \208\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    319. The ``public protection'' provisions of the Paperwork
Reduction Act of 1995 requires each agency to display a currently valid
control number and inform respondents that a response is not required
unless the information collection displays a valid OMB control number
on each information collection or provides a justification as to why
the information collection number cannot be displayed. In the case of
information collections published in regulations, the control number is
to be published in the Federal Register.
    320. Public Reporting Burden: In the NOPR, the Commission based its
estimate of the Public Reporting Burden on the NERC Compliance
Registry, as of March 3, 2009, and on NERC's July 30, 2008 petition for
approval of PRC-023-1. The Commission stated that, as of March 3, 2009,
NERC had registered in its Compliance Registry: (1) 568 distribution
providers; (2) 825 generator owners; (3) 324 transmission owners; and
(4) 79 planning authorities. The Commission also noted that the
Reliability Standard does not apply to all transmission owners,
generator owners, and distribution providers, but only to those with
load-responsive phase protection systems as described in Attachment A
of the Standard, applied to all transmission lines and transformers
with low-voltage terminals operated or connected at 200 kV and above
and between 100 kV and 200 kV as identified by the planning coordinator
as critical to the reliability of the bulk electric system. The
Commission further noted that some entities are registered for multiple
functions, so there is some overlap between the entities registered as
distribution providers, transmission owners, and generator owners.
Given these parameters, the Commission estimated the Public Reporting
Burden as follows:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           Number of       Number of
            Data collection               respondents      responses              Hours per respondent                      Total annual hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC-725G:
M1--TOs, GOs and DPs must ``have                   450               1  Reporting: 0...........................  Reporting: 0.
 evidence'' to show that each of its
 transmission relays are set according
 to Requirement R1.
                                                                        Recordkeeping: 100.....................  Recordkeeping: 45,000.
M2--Certain TOs, GOs and DPs must have             166               1  Reporting: 0...........................  Reporting: 0.
 evidence that a facility rating was
 agreed to by PA, TOP and RC.
                                                                        Recordkeeping: 10......................  Recordkeeping: 1,660.
M3--PC must document process for                    79               1  175....................................  13,825.
 determining critical facilities and
 (2) a current list of such facilities.
                                       -----------------------------------------------------------------------------------------------------------------
    Total.............................  ..............  ..............  .......................................  60,485.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on the available information from the compliance registry,
the Commission estimated that 525 entities would be responsible for
compliance with the Reliability Standard.\209\ The Commission also
estimated that it would require 60,485 total annual hours for
collection (reporting and recordkeeping) and that the average
annualized cost of compliance would be $2,419,400 ($40/hour for 60,485
hours; the Commission based the $40/hour estimate on $17/hour for a
file/record clerk and $23/hour for a supervisor).\210\
---------------------------------------------------------------------------

    \209\ NOPR, FERC Stats. & Regs. ] 32,642 at P 117.
    \210\ BPA notes that the NOPR erroneously showed this figure as
$241,940 rather than $2,419,400.
---------------------------------------------------------------------------

    321. Several commenters express concern with the burden to be
imposed by the Reliability Standard. Some of these comments address the
Reliability Standard's potential impact on small entities; because
these comments are also the subject of the analysis

performed under the Regulatory Flexibility Act, the Commission has
provided a response under that section of this rulemaking. Other
comments question the Commission's initial burden estimate.
    322. APPA argues that the Commission has grossly underestimated the
Public Reporting Burden and requests that the Commission develop a more
accurate estimate. APPA notes that the Commission provided a breakdown
by category of registered entities for a total of 1,717 entities, but
then asserts that only 525 entities will be subject to PRC-023-1 as
proposed by NERC. APPA states that it cannot assess how the Commission
came up with this lower number, as the Commission provided no
explanation of its methodology or the data it used to reach this
conclusion. APPA states that the Commission's initial estimate appears
to be based on the Reliability Standard as proposed by NERC, and
therefore fails to account for the Commission's proposals to expand the
Standard's applicability. APPA argues that the Commission must assess
the Public Reporting Burden created by its proposals.
    323. APPA also claims that the Commission's estimate of labor costs
is so low as to be completely erroneous for burden evaluation purposes.
Based on an informal survey of its members that own or operate
transmission facilities above 100 kV, APPA states that 21 out of nearly
300 registered public power utilities would need to evaluate 791
terminals to comply with the Commission's proposals. At an estimated
cost of between $500 and $1,200 per location, APPA estimates that the
cost of compliance for these 21 members would be between $395,500 and
$949,200; the Commission estimated $2,419,400 for the entire industry.
APPA adds that entities will need seasoned and expensive electrical
engineers and outside consultants to comply with the Commission's
proposals, not file/record clerks who are paid $17 per hour or
supervisory personnel who are paid $23 per hour. APPA reports that one
of its members estimates that it would have to use engineers, managers
and even director-level personnel to carry out the required tasks, at
an estimated cost of $55-$75 per hour. APPA expects that the cost of
external consultants could reach $200 per hour.
    324. BPA states that the loaded cost for an engineer is
approximately $80 per hour, twice the $40 per hour the Commission
estimated for a file clerk and a supervisor. BPA observes that this
would double the estimated annual cost of the Reliability Standard to
$4,838,800. BPA also questions the estimate of 100 hours annually for
each respondent to comply with Requirement R1. BPA states that it could
take thousands of hours for larger utilities.
    325. EEI argues that the Commission's estimate of hours for
reporting and recordkeeping substantially underestimates the actual
cost, in both time and money, required to comply with the Commission's
modifications. EEI reports that one smaller investor-owned utility has
estimated that it would take 4-8 hours of engineering time, per relay
terminal, to review the more than 850 line terminals on its system
operated between 100 kV and 200 kV. EEI states that it would take an
additional 6-12 hours of engineering time per terminal if, as the
utility expects, about one third of its line terminals require
mitigation, and another 6-12 hours of operations and maintenance staff
hours to implement relay settings for terminals requiring mitigation.
    326. EEI asserts that it could cost $40,000 to replace each
terminal in order to comply with the Commission's modifications. EEI
states that there are more than 100,000 line terminals in the U.S. on
facilities between 100 kV and 200 kV that would have to be checked if
the Commission adopts a ``rule out'' approach. EEI estimates that this
review could take 1.5 million labor hours, and another 750,000 hours if
just one-half of the terminals must be replaced. EEI states that the
aggregate cost to replace these terminals could exceed $2.4 billion.
    327. Given the Commission's decision not to adopt the ``rule out''
approach, most of these comments are no longer relevant. However, in
response to the comments that remain relevant, and upon further review,
we have revised our initial estimates as reflected below.
    Information Collection Costs: The Commission sought comments about
the information collection costs needed to comply with PRC-023-1. Since
many of the comments the Commission received estimated costs based on
the ``rule out'' approach, they are no longer applicable given our
decision in this Final Rule not to require the ``rule out'' approach.
However, some commenters argue, apart from the ``rule out'' approach,
that the NOPR underestimated the hours required to comply and the
estimated cost of labor. After further consideration, with respect to
the costs of labor, we agree that the $40/hour estimate for file/record
clerks and supervisory employees is not correct. We also agree with
commenters that electrical engineers will be required to comply with
PRC-023-1. Therefore, we have revised estimates as indicated below:
     Number of line terminals to be reviewed: 53,000.
     Number of hours per terminal: 6.4.
     Hourly rate for review by engineers: $120.

Total Cost for review = (terminals to be reviewed x hours per terminal)
x hourly rate for review by engineers = (53,000 x 6.4) x ($120/hour) =
339,200 hours x 120/hour = $40,704,000.

Sources

     Title: FERC-725-G ``Mandatory Reliability Standard for
Transmission Relay Loadability.''
     Action: Proposed Collection of Information.
     OMB Control No: [To be determined.]
     Respondents: Business or other for profit, and/or not for
profit institutions.
     Frequency of Responses: On Occasion.
     Necessity of the Information: The Transmission Relay
Loadability Reliability Standard, if adopted, would implement the
Congressional mandate of the Energy Policy Act of 2005 to develop
mandatory and enforceable Reliability Standards to better ensure the
reliability of the nation's Bulk-Power System. Specifically, the
proposed Reliability Standard would ensure that protective relays are
set according to specific criteria to ensure that relays reliably
detect and protect the electric network from all fault conditions, but
do not limit transmission loadability or interfere with system
operator's ability to protect system reliability.
    328. Interested persons may obtain information on the reporting
requirements by contacting: Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426 [Attention: Michael Miller,
Office of the Executive Director, Phone:<PHONE_NUMBER>, fax: (202)
273-0873, e-mail<EMAIL_ADDRESS>Comments on the
requirements of the proposed rule may also be sent to the Office of
Information and Regulatory Affairs, Office of Management and Budget,
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy
Regulatory Commission], e-mail<EMAIL_ADDRESS>
V. Environmental Analysis

    329. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human

environment.\211\ The Commission has categorically excluded certain
actions from this requirement as not having a significant effect on the
human environment. The actions proposed here fall within the
categorical exclusion in the Commission's regulations for rules that
are clarifying, corrective or procedural, for information gathering,
analysis, and dissemination.\212\ Accordingly, neither an environmental
impact statement nor environmental assessment is required.
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    \211\ Order No. 486, Regulations Implementing the National
Environmental Policy Act, 52 FR 47,897 (Dec. 17, 1987), FERC Stats.
& Regs. ] 30,783 (1987).
    \212\ 18 CFR 380.4(a)(5) (2009).
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VI. Regulatory Flexibility Act

    330. The Regulatory Flexibility Act of 1980 (RFA) \213\ generally
requires a description and analysis of any final rule that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking, but
rather requires consideration of alternatives that are less burdensome
to small entities and an agency explanation of why alternatives were
rejected.
---------------------------------------------------------------------------

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

    331. In drafting a rule, an agency is required to: (1) Assess the
effect that its regulation will have on small entities; (2) analyze
effective alternatives that may minimize a regulation's impact; and (3)
make the analyses available for public comment.\214\ In its NOPR, the
agency must either include an Initial Regulatory Flexibility Act
Analysis (Initial Analysis) \215\ or certify that the proposed rule
will not have a ``significant impact on a substantial number of small
entities.''\216\
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    \214\ 5 U.S.C. 601-604.
    \215\ 5 U.S.C. 603(a).
    \216\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

    332. If, in preparing the NOPR, an agency determines that the
proposal could have a significant impact on a substantial number of
small entities, the agency shall ensure that small entities will have
an opportunity to participate in the rulemaking procedure.\217\
---------------------------------------------------------------------------

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

    333. In its Final Rule, the agency must also either prepare a Final
Regulatory Flexibility Act Analysis (Final Analysis) or make the
requisite certification. Based on the comments the agency receives on
the NOPR, it can alter its original position as expressed in the NOPR
but it is not required to make any substantive changes to the proposed
regulation.
    334. The statute provides for judicial review of an agency's final
RFA certification or Final Analysis.\218\ An agency must file a Final
Analysis demonstrating a ``reasonable, good-faith effort'' to carry out
the RFA mandate.\219\ However, the RFA is a procedural, not a
substantive, mandate. An agency is only required to demonstrate a
reasonable, good faith effort to review the impact the proposed rule
would place on small entities, any alternatives that would address the
agency's and small entities' concerns and their impact, provide small
entities the opportunity to comment on the proposals, and review and
address comments. An agency is not required to adopt the least
burdensome rule. Further, the RFA does not require an agency to assess
the impact of a rule on all small entities that may be affected by the
rule, only on those entities that the agency directly regulates and
that are subject to the requirements of the rule.\220\
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    \218\ 5 U.S.C. 611.
    \219\ United Cellular Corp. v. FCC, 254 F.3d 78, 88 (DC Cir.
2001); Alenco Commc'ns, Inc. v. FCC, 201 F.3d 608, 625 (5th Cir.
2000).
    \220\ Mid-Tex Elec. Coop., Inc. v. FERC, 773 F.2d 327 (DC Cir.
1985).
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A. NOPR Proposal

    335. In the NOPR, the Commission asserted that most of the
entities, i.e., transmission owners, generator owners, distribution
providers, and ``planning coordinators,'' or alternatively ``planning
authorities,'' to which the requirements of this rule will apply, do
not fall within the applicable definition of ``small entities.'' The
Commission also stated that, based on available information regarding
NERC's compliance registry, approximately 525 entities will be
responsible for compliance with the new Reliability Standard.
Consequently, the Commission certified that the Reliability Standard
will not have a significant adverse impact on a substantial number of
small entities and that no RFA analysis was required.

B. Comments

    336. APPA, TAPS, NRECA, and SWTDUG argue that the ``rule out''
approach for 100 kV-200 kV facilities and the ``add in'' approach for
sub-100 kV facilities will cause the Reliability Standard to have a
significant adverse impact on a substantial number of small entities.
    337. NRECA argues that the Commission's Initial Analysis is
inadequate and its conclusion premature given the Commission's
proposals to expand the Reliability Standard's applicability. NRECA
argues that the Commission cannot develop an adequate Final Analysis
without an Initial Analysis that lays the proper foundation for
eliciting comments and seeking information. APPA argues that the
Commission's Initial Analysis is flawed and fails to: (1) Assess the
effect the regulation will have on small entities; (2) analyze
effective alternatives that might minimize the regulation's impact; and
(3) make such an analysis available for public comment.
    338. APPA and NRECA also argue that the Commission failed to: (1)
Provide its basis for claiming that only 525 entities from the NERC
Compliance Registry will be required to comply with the Reliability
Standard; (2) justify its assertion that the majority of the expected
525 entities required to comply do not qualify as small entities under
the Small Business Act; (3) state how many of the 525 affected entities
are small entities; and (4) identify the registered entities that are
required to comply. APPA argues that the Commission's expectation that
525 facilities will be required to comply with the Reliability Standard
is based on the Reliability Standard as proposed by NERC, and does not
account for the Commission's potentially broader applicability
proposals. APPA states that 261 of its members are registered entities
and qualify as small entities. NRECA adds that a substantial majority
of its approximately 930 rural electric cooperative members are small
entities that would be adversely impacted by the proposed rule.
    339. TAPS argues that the ``rule out'' approach will increase the
burden on small systems and may force the Commission to depart from the
Compliance Registry criteria that formed the basis for its RFA
certification in Order No. 693. TAPS explains that if the ``rule out''
approach will make all 100 kV facilities subject to the Reliability
Standard, including radial transmission lines, then the Standard will
apply to unregistered small entities that have not previously been
considered part of the bulk electric system and therefore do not appear
on the Compliance Registry that served as the basis for the
Commission's small entity impacts analysis.

C. Commission Determination

    340. As discussed previously in this Final Rule, the Commission
will not adopt the NOPR proposal to make PRC-023 applicable to all
facilities operated at or above 100 kV, ``ruling out'' those facilities
that would not demonstrably result in cascading outages, instability,
uncontrolled separation, violation of facility ratings, or interruption
of firm transmission service. Accordingly, to

the extent that the Commission has decided to abandon the ``rule out''
approach in favor of an ``add-in'' approach, as discussed in previous
portions of this Final Rule, the Commission expects that many of the
concerns and impact estimates submitted by commenters are moot or no
longer accurate.
    341. Nonetheless, the Commission does find it appropriate to
address commenters' concern regarding the number of entities that the
Commission estimates will be subject to PRC-023-1 as proposed by NERC.
Based on the Compliance Registry dated November 30, 2009, there are 573
entities registered as Distribution Providers, 821 entities registered
as Generator Owners, 323 entities registered as Transmission Owners,
and 80 entities registered as Planning Authorities. However, the
Commission notes that some entities are registered for multiple
functions, and therefore recognizes that there is some overlap between
the entities registered as a Distribution Provider, Transmission Owner,
Generator Owner, and/or Planning Authority. Therefore, after
eliminating any duplicative registrations, the Commission finds that
there are 1301 entities that are registered as engaging in one or more
of the applicable functions within the scope of PRC-023-1.
    342. Reliability Standard PRC-023-1 applies to Transmission Owners,
Generator Owners, and Distribution Providers with load-responsive phase
protection systems as described in Attachment A of the Reliability
Standard, applied to facilities defined in requirements 4.1.1 through
4.1.4.\221\ The Reliability Standard applies to facilities 100 kV and
above and to transformers with low-voltage terminals 200 kV and above.
Because there are no commercial generators with a terminal voltage as
high as 100 kV and all generator step-up and auxiliary power
transformers have low-voltage windings well below 200 kV, PRC-023-1
excludes generators and all generator step-up and auxiliary
transformers. Therefore, no generator owner that is not also a
transmission owner and/or a distribution provider will be subject to
PRC-023-1. Accordingly, the Commission calculates that the potential
applicability of the Final Rule may be reduced by 623, which is the
total number of entities registered solely as a generator owner. Thus,
the Commission anticipates that the Final Rule will apply to
approximately 678 entities overall.\222\
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    \221\ As proposed, the Commission notes PRC-023-1 is applicable
to Generator Owners with load-responsive phase protection systems as
described in Attachment A, applied to facilities defined in 4.1.1
through 4.1.4., however, excludes generator protection relays that
are susceptible to load in Section (3) of Attachment A.
    \222\ The Commission derives this result by using the following
equation: 1301 applicable entities (entities registered as one of
more of the following functions: Distribution Provider, Transmission
Owner, Generator Owner, and Planning Authority)--623 entities
registered solely as a Generator Owner = 678.
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    343. According to the Department of Energy's Energy Information
Administration (EIA), there were 3271 electric utility companies in the
United States in 2007,\223\ and approximately 3012 of these electric
utilities qualify as small entities under the Small Business Act (SBA)
definition.\224\ Of those 3012 small entities, only 80 entities also
appear in the NERC Compliance Registry. Accordingly, the Commission
estimates that the Reliability Standard will affect a maximum of 80
SBUs, or approximately 12 percent of those entities estimated to be
subject to the requirements of the Final Rule.
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    \223\ See U.S. Energy Information Administration, Form EIA-861,
Dept. of Energy (2007), available at http://www.eia.doe.gov/cneaf/
electricity/page/eia861.html.
    \224\ According to the SBA, a small electric utility is defined
as one that has a total electric output of less than four million
MWh in the preceeding year.
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    344. Based upon on this revised analysis, we certify that this
Final Rule will not have a significant economic impact on a substantial
number of small entities. Accordingly, no further RFA analysis is
required.

VII. Document Availability

    345. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    346. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    347. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
VIII. Effective Date and Congressional Notification

    348. These regulations are effective 45 days from publication in
Federal Register for non-major rules and 60 days from the later of the
date Congress receives the agency notice or the date the rule is
published in the Federal Register. The Commission has determined, with
the concurrence of the Administrator of the Office of Information and
Regulatory Affairs of OMB, that this rule is not a ``major rule'' as
defined in section 351 of the Small Business Regulatory Enforcement
Fairness Act of 1996.

List of Subjects in 18 CFR Part 40

    By the Commission.

Kimberly D. Bose,
Secretary.

    Note: The following Appendix will not appear in the Code of
Federal Regulations.

                                             Appendix A--Commenters
----------------------------------------------------------------------------------------------------------------
                       Abbreviation                                              Commenter
----------------------------------------------------------------------------------------------------------------
Alcoa....................................................  Alcoa, Inc.
Ameren...................................................  Ameren Services Company.
APPA.....................................................  American Public Power Association.
ATC......................................................  American Transmission Company, LLC.
Austin Energy............................................  City of Austin, Texas.
Basin....................................................  Basin Electric Cooperative.
BPA......................................................  Bonneville Power Administration.
California Commission....................................  Public Utilities Commission of the State of
                                                            California.
City Utilities of Springfield............................  City Utilities of Springfield, Missouri.

Consumers Energy.........................................  Consumers Energy Company.
CRC......................................................  Colorado River Commission of Nevada.
Dominion.................................................  Dominion Resources, Inc.
Duke.....................................................  Duke Energy Corporation.
EEI......................................................  Edison Electric Institute.
ElectriCities............................................  ElectriCities of North Carolina, Inc.
Entergy..................................................  Entergy Services, Inc.
E.ON.....................................................  E.ON U.S. LLC.
EPSA.....................................................  Electric Power Supply Association.
ERCOT....................................................  Electric Reliability Council of Texas, Inc.
Exelon...................................................  Exelon Corporation.
Fayetteville Public Works Commission.....................  Fayetteville Public Works Commission.
Filing Cooperatives......................................  Mohave Electric Cooperative, Inc., Trico Electric
                                                            Cooperative, inc., Navopache Electric Cooperative,
                                                            Inc., and Sulphur Springs Valley Electric
                                                            Cooperative, Inc.
Georgia Transmission.....................................  Georgia Transmission Corporation.
IESO/Hydro One...........................................  Independent Electricity System Operator and Hydro One
                                                            Networks Inc.
IRC......................................................  The ISO/RTO Council.
ISO New England..........................................  ISO New England Inc.
ITC......................................................  International Transmission Company.
Joint Commenters.........................................  Independent Electricity System Operator, PJM
                                                            Interconnection L.L.C., Southwest Power Pool, and
                                                            Midwest Independent Transmission Operator.
LES......................................................  Lincoln Electric System.
Manitoba Hydro...........................................  Manitoba Hydro.
McDonald.................................................  Michael McDonald.
MDEA Cities..............................................  Mississippi Delta Energy Agency, Clarksdale Public
                                                            Utilities Commission of the City of Clarksdale,
                                                            Mississippi, and the Public Service Commission of
                                                            Yazoo City of the City of Yazoo City, Mississippi.
MEAG.....................................................  Municipal Electric Authority of Georgia.
NARUC....................................................  National Association of Regulatory Utility
                                                            Commissioners.
NERC.....................................................  North American Electric Reliability Corporation.
New York Commission......................................  New York State Public Service Commission.
NRECA....................................................  National Rural Electric Cooperative Association.
NV Energy................................................  NV Energy.
NWCP.....................................................  Northern Wasco County People's Utility District.
Oncor....................................................  Oncor Electric Delivery Company LLC.
Ontario Generation.......................................  Ontario Power Generation Inc.
PacifiCorp...............................................  PacifiCorp.
Pacific Northwest State Commissions......................  Washington Utilities and Transportation Commission,
                                                            Idaho Public Utilities Commission, Public Utility
                                                            Commission of Oregon, and Montana Public Service
                                                            Commission.
Palo Alto................................................  City of Palo Alto, California.
PG&E.....................................................  Pacific Gas & Electric Company.
Portland General.........................................  Portland General Electric Company.
PSEG Companies...........................................  Public Service Electric & Gas Company, PSEG Energy
                                                            Resources & Trade LLC, PSEG Power LLC.
Public Power Council.....................................  Public Power Council.
Seattle City Light.......................................  Seattle City Light.
Six California Cities....................................  Cities of Anaheim, Azusa, Banning, Colton, Pasadena,
                                                            and Riverside, California.
SoCalEd..................................................  Southern California Edison Company.
South Carolina E&G.......................................  South Carolina Electric & Gas Company.
Southern.................................................  Southern Company Services, Inc.
SRP......................................................  Salt River Project Agricultural Improvement and Power
                                                            District.
SWTDUG...................................................  Southwest Transmission Dependent Utility Group.
TANC.....................................................  Transmission Agency of Northern California.
TAPS.....................................................  Transmission Access Policy Study Group.
Tri-State................................................  Tri-State Generation & Transmission Association.
TVA......................................................  Tennessee Valley Authority.
WAPA-RMR.................................................  Western Area Power Administration-Rocky Mountain
                                                            Region.
WECC.....................................................  Western Electricity Coordinating Council Relay Work
                                                            Group.
Y-WEA....................................................  Y-W Electric Association, Inc.
----------------------------------------------------------------------------------------------------------------

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