diurnal studies. However, we recognize that it is possible that the
loads used to represent extreme heat and cold events will include the
effects of demand load response because entities' load data obtained
from historical data during these past extreme events will reflect the
effects of demand load response. If that is the case, demand load
response will be automatically factored into the benchmark planning
case. Thus, in addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to
ensure that the impacts of demand load response are accurately modeled
in extreme weather studies, such as by analyzing demand load response
as a sensitivity, as is currently the case under Reliability Standard
TPL-001-5.1.\187\
---------------------------------------------------------------------------

    \187\ Reliability Standard TPL-001-5.1, at Requirement 2.1.3.
---------------------------------------------------------------------------

2. Sensitivity Analysis
    118. In the NOPR, the Commission proposed directing NERC to
establish a requirement for responsible entities to consider system
models and sensitivity cases when assessing extreme heat and extreme
cold weather.\188\ The NOPR explained that, while Reliability Standard
TPL-001-5.1 requires the use of sensitivity power flow cases, the
Standard does not require responsible entities to model the
simultaneous variation of load, generation, and transfers necessary to
account for the impacts of extreme heat and cold weather events. This,
in turn, could result in failure to detect in the planning horizon
potential reliability issues such as widespread outages and cascading
failures.\189\
---------------------------------------------------------------------------

    \188\ NOPR, 179 FERC ] 61,195 at P 73. Sensitivity analyses
consider the impact on a base case by altering discrete variables.
    \189\ Id.
---------------------------------------------------------------------------

    119. The NOPR further stated that to accurately model the impacts
of extreme heat and cold weather events it would be necessary to define
and model in sensitivity analyses demand probability scenario cases,
generators that are affected by these events (i.e., wind tripping off,
solar dropping off, gas plants not being operational due to gas
restrictions/freeze-offs, etc.) and transfer levels.\190\
---------------------------------------------------------------------------

    \190\ Id.
---------------------------------------------------------------------------

    120. The NOPR requested comment on: (1) whether to require
transmission planners and planning coordinators to assess reliability
in the planning horizon for sensitivity cases in which multiple inputs
(e.g., load and generator failures) change simultaneously during
extreme heat and cold events; and (2) the range of factors and the
number of sensitivity cases that should be considered to ensure
reliable planning.\191\
---------------------------------------------------------------------------

    \191\ Id. P 74.
---------------------------------------------------------------------------

a. Comments
    121. Some commenters support requiring the consideration of certain
sensitivities. For example, AEP recommends that a baseline set of
sensitivities should be defined by the NERC standard drafting team and
there should be flexibility for planning coordinators to introduce
further sensitivities if deemed necessary.\192\ EPRI suggests that
multiple hours may need to be studied over the course of the extreme
temperature window to capture sensitivities related to generation and
demand that can lead to differing steady state and dynamic stability
impacts. EPRI also recommends that in addition to the sensitivities
driven by the operational performance of the system, the standard
should include other external drivers that may compound system
conditions during the extreme temperature events, such as a concurrent
lull in wind speeds that would limit wind generation outputs.\193\
---------------------------------------------------------------------------

    \192\ AEP Comments at 12.
    \193\ EPRI Comments at P 22.
---------------------------------------------------------------------------

    122. Other commenters suggest reasons why it may not be necessary
for the Commission to direct the study of additional sensitivities.
NYISO and LCRA explain that extreme heat and cold weather impacts and
unavailability of natural gas fuel are already studied as sensitivities
under Reliability Standard TPL-001-5.1.\194\ Similarly, Indicated Trade
Associations assert that the extreme weather base case should already
represent system conditions at or near possible seasonal extreme
weather limits and that, as such, many additional sensitivities may not
be necessary.\195\ LCRA adds that the effect of changing inputs (e.g.,
load and generation, including generation retirements and forced
generation outages) should be captured in the contingency definitions,
performance requirements, and analysis for the given region and extreme
weather case.\196\
---------------------------------------------------------------------------

    \194\ NYISO Comments at 13; LCRA Comments at 3.
    \195\ Indicated Trade Associations Comments at 10.
    \196\ LCRA Comments at 3.
---------------------------------------------------------------------------

    123. Idaho Power, APS, and Indicated Trade Associations indicate
that given the diversity among utilities with respect to load profiles,
geographic footprint, resource mix, particular utility, its resource
mix, and geographic footprint, and available resources and needs, the
Commission should allow entities to select the sensitivities they will
study.\197\
---------------------------------------------------------------------------

    \197\ Indicated Trade Associations Comments at 11; Idaho Power
Comments at 4-5; APS Comments at 7.
---------------------------------------------------------------------------

b. Commission Determination
    124. Pursuant to section 215(d)(5) of the FPA, we adopt the NOPR
proposal and direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission
planner to determine if the results of the base case are sensitive to
changes in the inputs. The use of sensitivity analyses is particularly
necessary when studying extreme heat and cold events because some of
the assumptions made when developing a base case may change if
temperatures change--for example, during extreme cold events, load may
increase as temperatures decrease, while a decrease in temperature may
result in a decrease in generation. We agree with AEP, and we direct
NERC to define during the Reliability Standard development process a
baseline set of sensitivities for the new or modified Reliability
Standard. While we do not require the inclusion of any specific
sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and
system transfers.\198\
---------------------------------------------------------------------------

    \198\ NOPR, 179 FERC ] 61,195 at P 73.
---------------------------------------------------------------------------

    125. We do not agree with Idaho Power, APS, and Indicated Trade
Associations that responsible entities alone should determine the
sensitivity cases that must be considered in the responsible entity's
study. Failure to consider variations in conditions necessary to
reflect extreme heat or cold weather events could result in major
reliability risks being overlooked and undetected in the planning
horizon.\199\ We do, however, believe that responsible entities should
be free to study additional sensitivities relevant to their planning
areas. Because wide-area studies conducted under the new or modified
Reliability Standard will be likely based on footprints significantly
larger than those typically concerned under Reliability Standard TPL-
001.5.1, cooperation will be necessary between responsible entities
conducting extreme heat and cold weather studies and other registered
entities within their extreme weather study footprints to ensure the
selection of appropriate sensitivities. EPRI's comment further
highlights the need for coordination between

registered entities to capture sensitivities related to variable energy
resources and demand.
---------------------------------------------------------------------------

    \199\ See id.
---------------------------------------------------------------------------

    126. We disagree with NYISO and LCRA that extreme heat and cold
weather impacts are already studied as sensitivities under Reliability
Standard TPL-001-5.1. Although TPL-001-5.1 mandates sensitivity
analysis by varying one or more conditions specified in the standard
such as load, generation, and transfers, this analysis alone cannot
capture the complexities of extreme heat and cold weather conditions.
Sensitivity analyses consider the impact on a base case of the
variability of discrete variables. Extreme heat and cold weather
impacts, on the other hand, may include numerous concurrent outages and
derates which cannot be studied as part of a single-variable
sensitivity analysis. Under the new or modified Reliability Standard,
however, these outages will be captured in the benchmark planning case
upon which sensitivity analyses will be performed.
3. Modifications to the Traditional Planning Approach
    127. In the NOPR, the Commission proposed to direct NERC to
consider alternative planning methods and techniques that diverge from
past Reliability Standard requirements to better capture the challenges
posed by extreme heat and cold events.\200\
---------------------------------------------------------------------------

    \200\ Id. P 75.
---------------------------------------------------------------------------

    128. The NOPR stated that Reliability Standard TPL-001-5.1 is based
on a deterministic approach, which uses planned contingencies and
specific performance criteria to study system response to various
conditions. This approach yields accurate planning when the power
supply is highly dispatchable, weather is predictable, and near-record
peak demand is reached only a few days a year.\201\ However, as noted
in the NOPR, the current planning approach applied in Reliability
Standard TPL-001-5.1 likely is not sufficient to accurately
characterize the reliability risk from extreme heat and cold weather
given the high degree of uncertainty inherent in predicting severe
weather and its impact on generation resources, transmission, and
load.\202\
---------------------------------------------------------------------------

    \201\ Id.
    \202\ Id.
---------------------------------------------------------------------------

    129. The NOPR explained the value of establishing a new or modified
planning approach to better capture the impacts of, and ensure reliable
planning and operation in response to, extreme heat and cold
events.\203\ Specifically, the NOPR mentioned as an option expanding
current deterministic studies to include probabilistically developed
scenarios as an option to better account for uncertainties during
extreme heat and cold weather conditions, since probabilistic tools can
capture ``random uncertainties in power system planning, including
those in load forecasting, generator performance, and failures of
system equipment.'' \204\
---------------------------------------------------------------------------

    \203\ Id. P 78.
    \204\ Id. P 79.
---------------------------------------------------------------------------

    130. Finally, the NOPR sought comments on combining or layering
probabilistic and deterministic approaches when planning for extreme
heat and cold weather conditions in the context of Reliability Standard
TPL-001-5.1. Specifically, the NOPR sought comments on the use of a
hybrid deterministic/probabilistic planning approach and the following:
(1) the assumptions from the deterministic and probabilistic approaches
that should be applied to study extreme heat and cold weather events;
(2) the potential planning challenges from combining the two planning
approaches; (3) the costs associated with adjustments to the currently
applied deterministic approach; (4) the implementation period necessary
for proposed changes; and (5) the reliability benefits that could
result.\205\
---------------------------------------------------------------------------

    \205\ Id.
---------------------------------------------------------------------------

a. Comments
    131. Many commenters support the use of probabilistic methods in
transmission planning to account for uncertainty in availability of
transmission and generation in extreme weather conditions.\206\ For
example, PJM states that the use of probabilistic modeling ``would help
establish the baseline and sensitivity system conditions upon which
deterministic approaches for go/no-go corrective action transmission
build decisions would be made.'' \207\ EPRI discusses potential
deficiencies in traditional deterministic approaches in planning
studies in cases where uncertainty and variability will increase on
both the generation and demand side across a variety of temperature
extremes. EPRI raises concerns that scenarios or system conditions that
result in consequential stability implications may not be adequately
captured in the planning models using the traditional deterministic
approach.\208\ ACP states that there is precedent for using
probabilistic tools in assessing electric reliability, as these methods
are widely used by utilities and RTOs to assess resource adequacy and
loss of load risk.\209\
---------------------------------------------------------------------------

    \206\ See, e.g., NESCOE Comments at 9; EPRI Comments at P 24;
PJM Comments at 11; EDF Comments at 20; PIOs Comments at 7; ACEG
Comments at 7; NARUC Comments at 5-6; ACP Comments at 15; Entergy
Comments at 6.
    \207\ PJM Comments at 11.
    \208\ EPRI Comments at P 24.
    \209\ ACP Comments at 16.
---------------------------------------------------------------------------

    132. Other commenters do not support a requirement to use
probabilistic methods. For example, while AEP recognizes the value of
probabilistic methods, it warns that the industry is not yet ready
because the necessary methods, frameworks, and tools are not yet
available to transmission planners.\210\ Several other commenters warn
that it would be premature to require the use of probabilistic
methods.\211\ Trade Associations express concern that probabilistic
planning based on extremely low probability events is highly
speculative and dependent on the judgment of planners, which increases
the complexity and risk associated with the development of transmission
projects, hampering the construction of needed transmission.\212\ Idaho
Power also does not think converting to a probabilistic approach is
necessary as sensitivities with appropriate inputs will capture the
impacts of extreme weather using deterministic techniques.\213\ LCRA
comments that probabilistic analysis requires large samples (i.e.,
number of events), but given the infrequent occurrence of extreme
weather events, it would be challenging to layer probabilistic
assumptions into transmission planning analyses.\214\
---------------------------------------------------------------------------

    \210\ AEP Comments at 22.
    \211\ APS Comments at 7 (requesting that the Commission hold
``robust industry-wide discussions to discuss probabilistic
approaches''); Tri-State Comments at 8.
    \212\ Trade Associations Comments at 11.
    \213\ Idaho Power Comments at 5.
    \214\ LCRA Comments at 3-4.
---------------------------------------------------------------------------

    133. Supporters of the use of probabilistic methods acknowledge
that implementation poses challenges. For example, EPRI comments that
implementation of probabilistic methods would require new processes to
link and communicate data across models, such as linking generation and
transmission expansion assessments, resource adequacy, production cost
models, and transmission planning assessments.\215\ Further, new
statistical methods and processes will be needed to inform the
selection of powerflow cases for planning assessments.\216\ PJM states
that the benefits of applying probabilistic methods would require
knowing in advance pre-established bounded parameter ranges, so

reasonable selection of probabilistic method assumptions lead to
benchmark planning cases that reflect statistically credible
scenarios.\217\ PJM further states that this should be the result of
coordinated analysis among RTOs, NOAA, DOE Labs, and NERC.\218\ Entergy
asserts that the probabilistic approach is significantly more
complicated than deterministic planning and cautions that any
requirement for probabilistic planning must have requirements that
reasonably can be performed, are assessable, and are auditable for
compliance.\219\ Because of the potential challenges associated with
implementing probabilistic planning requirements, Tri-State recommends
the further study of and development of best practices for
probabilistic planning.\220\
---------------------------------------------------------------------------

    \215\ EPRI Comments at P 25.
    \216\ Id.
    \217\ PJM Comments at 11.
    \218\ Id.
    \219\ Entergy Comments at 9.
    \220\ Tri-State Comments at 8.
---------------------------------------------------------------------------

b. Commission Determination
    134. Pursuant to section 215(d)(5) of the FPA, the Commission
adopts and modifies the NOPR proposal and directs NERC to require in
the new or modified Reliability Standard the use of planning methods
that ensure adequate consideration of the broad characteristics of
extreme heat and cold weather conditions. We further direct NERC to
determine during the standard development process whether probabilistic
elements can be incorporated into the new or modified Reliability
Standard and implemented presently by responsible entities. If NERC
identifies probabilistic elements which responsible entities can
feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.
    135. Including probabilistic scenarios in the planning process
could result in a planning approach that better captures the
uncertainties of extreme weather events, thus better preparing
responsible entities to ensure Reliable Operation under stressed
conditions.\221\ Further, we agree with commenters that the use of
probabilistic methods by responsible entities would help ensure
Reliable Operation of the Bulk-Power System as probabilistic methods
better characterize multi-day wide-area events such as extreme heat and
cold events.\222\
---------------------------------------------------------------------------

    \221\ NOPR, 179 FERC ] 61,195 at P 76.
    \222\ EPRI Comments at 4.
---------------------------------------------------------------------------

    136. However, we recognize, as certain commenters point out, that a
prescriptive requirement to add probabilistic planning methods to
better understand reliability implications could be met by significant
challenges. Some of the challenges identified by commenters include
lack of commercially available tools required for probabilistic
modeling and lack of planning staff trained in the use of these tools
and in carrying out probabilistic studies. Further, there may be a need
to develop and maintain probabilistic databases that include, for
example, outage data from extreme weather-dependent grid components and
generation resources.
    137. Because of these implementation concerns, we believe that the
best course of action is to allow NERC to use its expertise and the
standard development process to address the concerns identified by
commenters and develop proposed modifications to existing planning
methods that address the Commission's directive to use transmission
planning methods that adequately characterize the effects of extreme
heat and cold weather conditions on the transmission system, including
incorporating probabilistic elements where possible. The standard
development process will also provide an adequate forum in which to
evaluate the many recommendations that commenters have presented in
response to the NOPR.
    138. We also direct NERC to identify during the standard
development process any probabilistic planning methods that would
improve upon existing planning practices, but that NERC deems
infeasible to include in the proposed Reliability Standard at this
time. If any such methods are identified, NERC shall describe in its
petition for approval of the proposed Reliability Standard the barriers
preventing the implementation of those probabilistic elements. We
intend to use this information to determine whether and what next steps
may be warranted to facilitate the use of probabilistic methods in
transmission system planning practices.

H. Implement a Corrective Action Plan if Performance Standards Are Not
Met

    139. The NOPR noted that under the currently effective Reliability
Standard TPL-001-5.1, planning coordinators and transmission planners
are required to evaluate possible actions to reduce the likelihood or
mitigate the consequences of extreme weather events, but are not
obligated to develop corrective action plans, even if such events are
found to cause cascading outages.\223\ Because of the potential
severity of extreme heat and cold weather events and their likelihood
to cause system instability, uncontrolled separation, or cascading
failures as a result of a sudden disturbance or unanticipated failure
of system elements, the NOPR proposed to direct NERC to require
corrective action plans that include mitigation for any instances where
performance requirements for extreme heat and cold events are not
met.\224\
---------------------------------------------------------------------------

    \223\ NOPR, 179 FERC ] 61,195 at P 83. Reliability Standard TPL-
001-5.1, Requirements R3.3.5 and R4.4.5 require computer simulation
analyses of extreme events listed in Table 1 of the standard (some
listed are examples and are not definitive), and if the analysis
concludes there is cascading caused by the occurrence of extreme
events, an evaluation of possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted.
    \224\ Id.
---------------------------------------------------------------------------

    140. Consistent with the existing requirements of Reliability
Standard TPL-001-5.1, the NOPR proposed to provide responsible entities
with the flexibility to determine the actions to include in their
corrective action plans to remedy identified deficiencies in
performance. The NOPR included several examples of actions that could
be included in a corrective action plan: planning for additional
contingency reserves or implementing new energy efficiency programs to
decrease load, increasing intra- and inter-regional transfer
capabilities, transmission switching, or adjusting transmission and
generation maintenance outages based on longer-lead forecasts. The NOPR
observed that well-planned mitigation and corrective actions that
account for some of these contingencies will minimize loss of load and
improve resilience during extreme heat and cold weather events.\225\
---------------------------------------------------------------------------

    \225\ Id. P 84.
---------------------------------------------------------------------------

    141. The NOPR explained that increases in interregional transfer
capability could be considered as one option to address potential
reliability issues during extreme weather events.\226\ The NOPR noted
that such transfer capability would allow an entity in one region with
available energy to assist one or more entities in another region that
is experiencing an energy shortfall due to the extreme weather
event.\227\ Increasing interregional transfer capability may be a
particularly robust option for planning entities attempting to mitigate
the risks associated with concurrent generator outages over a wide
area.\228\
---------------------------------------------------------------------------

    \226\ Id. P 85.
    \227\ Id.
    \228\ Id. In this proceeding, we refer to interregional transfer
capability strictly in the context of improving the reliability of
the Bulk-Power System through improved transmission system planning
and associated modifications to NERC's Reliability Standards.

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

    142. To ensure the timely development and implementation of
corrective action plans, the NOPR sought comments on the timeframe for
developing such corrective action plans and sharing of the corrective
actions with other interconnected planning entities.\229\ In addition,
to identify opportunities for improved wide-area planning studies and
coordination, the NOPR requested comment on how to develop corrective
action plans that mitigate issues that require corrective action by,
and coordination among, multiple transmission owners.\230\
---------------------------------------------------------------------------

    \229\ Id.
    \230\ Id. P 67.
---------------------------------------------------------------------------

1. Comments
a. Jurisdictional Issues
    143. Several commenters raise jurisdictional concerns regarding
corrective action plans.\231\ While Indicated Trade Associations
support the NOPR proposal to require corrective action plans addressing
vulnerabilities identified in the study process, they also urge that
the Commission ``remain mindful'' of the statutory limitation set forth
in FPA section 215(i) that NERC and the Commission do not have
authority ``to order the construction of additional generation or
transmission capacity or to set or enforce compliance with standards
for adequacy or safety of electric facilities or services.'' \232\ In
particular, Indicated Trade Associations express concern that certain
examples of potential corrective action plans mentioned in the NOPR,
including ``planning for additional contingency reserves . . . or
increasing intra- and inter-regional transfer capabilities,'' exceed
the Commission's authority under section 215 of the FPA.\233\
Similarly, Electric Reliability Council of Texas, Inc. (ERCOT) opines
that ``[r]equiring transmission planners to address what is
fundamentally a resource adequacy concern through the transmission
planning process would usurp the authority of the states, which are
responsible for ensuring the adequacy of the generation supply.'' \234\
---------------------------------------------------------------------------

    \231\ Indicated Trade Associations Comments at 11-12; ERCOT
Comments at 5.
    \232\ Indicated Trade Association Comments at 12 (citing 16
U.S.C. 824o(i)).
    \233\ Id. at 11-12; ERCOT Comments at 5.
    \234\ ERCOT Comments at 5.
---------------------------------------------------------------------------

b. Corrective Action Plans
    144. Most commenters agree that corrective action plans should be
required to address system performance issues identified in studies
under extreme heat and cold weather conditions.\235\ NERC agrees that
any revised Reliability Standard directed under a final rule issued in
this proceeding should require that entities develop corrective action
plans for instances where performance requirements for selected extreme
weather and environmental conditions are not met for at least some of
the planning scenarios.
---------------------------------------------------------------------------

    \235\ See, e.g., NERC Comments at 10; NARUC Comments at 6;
NESCOE Comments at 3; MISO Comments at 4.; PJM Comments at 12.
---------------------------------------------------------------------------

    145. BPA asserts that several of the corrective action plan
examples listed in the NOPR, such as transmission switching/
reconfiguration, or adjusting transmission and generation maintenance
outages, would likely be covered by Reliability Standard EOP-011-2,
requiring transmission operators and balancing authorities to have
operating plans to mitigate operating emergencies including determining
the reliability impacts of extreme weather conditions. Therefore, BPA
cautioned, any modifications to Reliability Standard TPL-001-5.1 should
be careful not to encroach upon the authority and discretion of
transmission operators and balancing authorities.\236\
---------------------------------------------------------------------------

    \236\ BPA Comments at 4.
---------------------------------------------------------------------------

    146. Some commenters do not support the NOPR proposal to require
the development and implementation of corrective action plans for all
instances where performance requirements for extreme heat and cold
events are not met. APS asserts that ``corrective action plans should
be focused on the most likely and impactful events, which may not
include extreme weather scenarios,'' and that as such, it disagrees
that corrective action plans ``should be required for results that come
out of sensitivity analysis, which includes extreme weather
scenarios.''
    147. With regard to costs, National Association of Regulatory
Utility Commissioners (NARUC) asserts that mitigation and corrective
actions to minimize loss of load and improve resilience should be
subjected to a cost/benefit analysis.\237\ Entergy suggests that the
Commission ``provide additional guidance regarding the level of
performance it expects during extreme heat and cold events,'' including
consideration of ``the cost effects on customers relative to the
potential risks and the time-frame in which those risks are likely to
arise.'' \238\
---------------------------------------------------------------------------

    \237\ NARUC Comments at 6.
    \238\ Entergy Comments at 2.
---------------------------------------------------------------------------

c. Generation and Transmission Capacity Increase and Resource Adequacy
Issues
    148. Most commenters agree that the responsible entities developing
corrective action plans should evaluate a range of solutions, including
transmission upgrades to increase interregional transfer capability
and/or building generation to address generation deficiency under
extreme weather events.\239\ Some commenters, however, question the
efficacy of corrective action plans and suggest that alternative
approaches are preferable.
---------------------------------------------------------------------------

    \239\ See, e.g., NARUC Comments at 6; UCS Comments at 9; PIOs
Comments at 15; AEP Comments at 5; ACEG Comments at 8; ACP Comments
at 11; Entergy Comments at 8.
---------------------------------------------------------------------------

    149. With regards to transmission capacity, and specifically
interregional transfer capabilities, many commenters agree that
adequate interregional transfer capability would help address
reliability challenges posed by extreme heat and cold weather
conditions.\240\ Some commenters urge the Commission to set a minimum
interregional transfer capability requirement.\241\ However, most
commenters addressing this topic opine that interregional transfer
requirements, including setting necessary or minimum transfer levels
and direction, should be addressed outside of the Reliability Standard
TPL-001-5.1 planning process.\242\ For example, MISO Transmission
Owners suggest that interregional transfers could be better dealt with
under Order No. 1000 Regional Transmission Planning processes.\243\
MISO recommends that corrective action plans require meaningful
mitigation, such as investment in transmission solutions, to address
issues identified in an extreme weather event study.\244\ Conversely,
Idaho Power states that if regional transmission facilities are to be
considered as corrective actions, Idaho Power would have concerns with
the efficacy of those corrective actions given the amount of time
necessary to build new transmission.\245\
---------------------------------------------------------------------------

    \240\ AEP Comments at 2; ACP Comments at 19; ACEG Comments at 9;
PJM Comments at 12; see MISO Transmission Owners Comments at 5-6.
    \241\ EDF Comments at 27; AEP Comments at 2; ACP Comments at 19;
ACEG Comments at 9; PJM Comments at 12.
    \242\ MISO Transmission Owners Comments at 5-6; ACP Comments at
19; ACEG Comments at 9; AEP Comments at 2.
    \243\ MISO Transmission Owners Comments at 5.
    \244\ MISO Comments at 4.
    \245\ Idaho Power Comments at 4, 6.
---------------------------------------------------------------------------

    150. Most commenters who disagree with the NOPR proposal to allow
entities to consider additional generation capacity as a corrective
action plan measure disagree on the

basis that resource adequacy is not a matter that should be dealt with
within the transmission planning process.\246\ For example, ISO-NE
asserts that the purpose of Reliability Standard TPL-001-5.1 is not to
ensure resource adequacy, but to ensure that load can be served.\247\
ACP and PIOs question the efficacy of building new generation as part
of a corrective action plan because such new generation may be subject
to the same issues as existing generation--for example, if an extreme
cold event leads to the outage of weather-sensitive generators, adding
more weather-sensitive generators will not resolve the resource
deficiency.\248\
---------------------------------------------------------------------------

    \246\ See, e.g., PJM Comments at 12; ERCOT Comments at 5; ISO-NE
Comments at 4.
    \247\ ISO-NE Comments at 4.
    \248\ ACP Comments at 6; PIOs Comments at 16.
---------------------------------------------------------------------------

d. Notification to Applicable Regulatory Authorities or Governing
Bodies Responsible for Retail Electric Service Issues
    151. ACP, New England States Committee on Electricity (NESCOE), and
Entergy comment that entities must coordinate with state and local
authorities in the development of corrective action plans involving
generation and transmission capacity.\249\ For example, NESCOE suggests
that corrective action plans be informed by state officials'
perspectives, consider a variety of mitigation options, and include a
detailed explanation of how the entity weighed the various
options.\250\ Additionally, NESCOE points out that given the likelihood
that corrective action plans will include load shed, state officials
should be involved in the corrective action plan process.\251\ NESCOE
proposes that responsible entities seek input from state regulators
during their planning process. Alternatively, NESCOE recommends the
adoption of the Joint Federal-State Task Force on Electric Transmission
model to create a similar task force focusing on extreme weather and
grid reliability.\252\
---------------------------------------------------------------------------

    \249\ See ACP Comments at 18; NESCOE Comments at 3; see also
Entergy Comments at 9 (stating in the context of the development of
corrective action plans that ``[t]he Commission also should ensure
that the relevant retail regulators have input into the level of
risks versus costs a transmission owner should accept.'').
    \250\ NESCOE Comments at 3.
    \251\ Id. at 5.
    \252\ Id. at 6.
---------------------------------------------------------------------------

2. Commission Determination
    152. Pursuant to section 215(d)(5) of the FPA, the Commission
adopts and modifies the NOPR proposal and directs NERC to require in
the new or modified Reliability Standard the development of extreme
weather corrective action plans for specified instances when
performance standards are not met. In addition, as explained below, we
direct NERC to develop certain processes to facilitate interaction and
coordination with applicable regulatory authorities or governing bodies
responsible for retail electric service as appropriate in implementing
a corrective action plan.
    153. We adopt our rationale set forth in the NOPR and conclude that
the directive to require the development of corrective action plans is
needed for Reliable Operation of the Bulk-Power System. Under the
currently effective Reliability Standard TPL-001-5.1, planning
coordinators and transmission planners are required to evaluate
possible actions to reduce the likelihood or mitigate the consequences
of extreme weather events, but are not obligated to develop corrective
action plans, even if such events are found to cause cascading outages.
Experience over the past decade has demonstrated that the potential
severity of extreme heat and cold weather events exacerbates the
likelihood to cause system instability, uncontrolled separation, or
cascading failures as a result of a sudden disturbance or unanticipated
failure of system elements. Thus, we conclude that entities should
proactively address known system vulnerabilities by developing
corrective action plans that include mitigation for specified instances
where performance requirements for extreme heat and cold events are not
met.
a. Jurisdictional Issues
    154. We reject the arguments that our directive to require
responsible entities to develop corrective action plans may exceed the
Commission's jurisdiction. Section 215(i)(2) of the FPA states that the
Commission and ERO are not authorized to order the construction of
additional generation or transmission capacity as part of a Reliability
Standard.\253\ Consistent with this limitation, the final rule does not
require any responsible entity to engage in the construction of
additional generation or transmission capacity. Moreover, while the
final rule directs NERC to include in a new or modified Reliability
Standard a requirement for entities to develop a corrective action plan
to address extreme heat and cold weather events during the transmission
planning process, the final rule does not mandate the use of any
specific mitigation measure.\254\
---------------------------------------------------------------------------

    \253\ 16 U.S.C. 824o(i)(2).
    \254\ NOPR, 179 FERC ] 61,195 at P 84 (``we believe it is
appropriate to provide responsible entities with the flexibility to
determine the best actions to include in their corrective action
plan to remedy any identified deficiencies in performance'').
---------------------------------------------------------------------------

    155. As noted by commenters, the NOPR provided examples of various
activities that may be appropriate under a corrective action plan, some
of which may require state or local authorizations (e.g., generation or
transmission development).\255\ Other examples mentioned in the NOPR
include ``implementing new energy efficiency programs to decrease load,
. . . transmission switching, or adjusting transmission and generation
maintenance outages based on longer-lead forecasts,'' \256\ none of
which involve the construction of generation or transmission capacity.
In addition, responsible entities have the option to use controlled
load shed as a mitigation measure. In sum, while responsible entities
would have the obligation to develop and implement a corrective action
plan, the Commission is not directing any specific result or content of
the corrective action plan. In such circumstances, the Commission's
directive does not exceed the jurisdictional limits set forth in
section 215(i) of the FPA.\257\
---------------------------------------------------------------------------

    \255\ Id.
    \256\ Id.
    \257\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 80 (D.C. Cir.
2014).
---------------------------------------------------------------------------

    156. In response to ERCOT and other commenters, the Commission's
action does not usurp state authority with regard to resource adequacy.
As explained above, the directive that responsible entities develop
corrective action plans in certain circumstances does not require the
construction of additional generation or transmission capacity.
Further, as discussed below, responsible entities that elect mitigation
activities that involve increased transmission or generation capacity
will of course be subject to the authority of such state agencies or
others with legal jurisdiction over the construction of transmission or
generation facilities.
b. Circumstances That Require Corrective Action Plans
    157. As stated above, we adopt and modify the NOPR proposal and
direct NERC to require in the new or modified Reliability Standard the
development of corrective action plans that include mitigation for
specified instances where performance requirements for extreme heat and
cold events are not met--i.e., when certain studies conducted under the
Standard show that an extreme heat or cold event would result in
cascading outages, uncontrolled separation, or instability.\258\ We
agree with APS that

neither version 4 nor 5.1 of Reliability Standard TPL-001-5.1 require
corrective action plans for extreme heat and cold weather events.
Extreme heat and cold weather events, which pose a serious risk to the
Reliable Operation of the Bulk-Power System, are increasing in
frequency and intensity. We believe that in taking steps to avoid
occurrences of cascading outages, uncontrolled separation, or
instability under extreme heat and cold, corrective action plans would
also minimize the extent and duration of loss of load and improve Bulk-
Power System resilience during extreme heat and cold weather
events.\259\
---------------------------------------------------------------------------

    \258\ NOPR, 179 FERC ] 61,195 at P 83.
    \259\ Id. P 84.
---------------------------------------------------------------------------

    158. Although the NOPR proposed requiring the development of
corrective action plans for any instance where performance requirements
for extreme heat and cold events are not met, we give NERC in this
final rule the flexibility to specify the circumstances that require
the development of a corrective action plan. For example, NERC should
determine whether corrective action plans should be required for single
or multiple sensitivity cases, and whether corrective action plans
should be developed if a contingency event that is not already included
in benchmark planning case would result in cascading outages,
uncontrolled separation, or instability.\260\ Because we also direct
NERC to establish required study contingencies and baseline
sensitivities,\261\ we believe it is necessary for NERC to develop
those aspects of the Standard prior to determining the instances under
which corrective action plans must be developed.
---------------------------------------------------------------------------

    \260\ Under Reliability Standard TPL-001-5.1, corrective action
plans are not required for single sensitivity cases.
    \261\ See supra PP 111, 124.
---------------------------------------------------------------------------

    159. With regard to BPA's suggestion that Reliability Standard EOP-
011-2 already addresses certain mitigation measures listed in the NOPR
as examples, we clarify that nothing in the final rule affects the
responsibilities or obligations of registered entities under that
Reliability Standard and note that there are important differences in
the scope and intent of EOP-011-2 and the Reliability Standard we are
directing be developed here. Specifically, while Reliability Standard
EOP-011-2 includes provisions to determine reliability impacts of
extreme cold conditions and extreme weather conditions,\262\ it does
not require the transmission operator to mitigate the condition. In
addition, Reliability Standard EOP-011-2 addresses the issues within
the operating time frame. Corrective action plans, as proposed in the
NOPR, would be developed in the planning horizon to address the issues
in the long-term planning time frame. Simultaneously, such issues would
be addressed by Reliability Standard EOP-011-2 in the operating time
frame should the studied extreme weather condition occur. As such,
there would not be any encroachment or conflict between the two
standards.
---------------------------------------------------------------------------

    \262\ Reliability Standard EOP-011-2, Requirement 1.2.6.
---------------------------------------------------------------------------

    160. With respect to arguments from NARUC and Entergy that the
Commission should require cost-benefit analysis for corrective action
plans or otherwise provide additional guidance as to the cost impacts
on customers, we decline to do so. FPA section 215 does not require the
use of cost-benefit analysis and, given the flexibility allowed to
responsible entities in crafting a corrective action plan, we are not
persuaded such a requirement would be warranted in this instance.
Regarding the cost impact on customers more generally, we believe that
NERC should have an opportunity in the first instance to balance such
impacts and present a new or modified Reliability Standard for
Commission approval. As articulated in Order No. 672, the cost of
compliance is but one factor in determining whether to approve a
proposed Reliability Standard and we will consider the potential cost
impacts in the context of the larger record.\263\
---------------------------------------------------------------------------

    \263\ See Order No. 672, 114 FERC ] 61,104 at P 330.
---------------------------------------------------------------------------

c. Generation and Transmission Capacity Increase and Resource Adequacy
Issues
    161. As discussed above, corrective action plans are not required
to use any specific mitigation measure and responsible entities are not
required to build transmission or generation. Nevertheless, some
entities may choose to include additional transmission or generation
capacity as a mitigation measure in their corrective action plan,
subject to the approval of relevant regulatory authorities.
    162. With respect to the use of transmission as a mitigation
measure, as stated in the NOPR and echoed by commenters, interregional
transfer capability can be a solution to some extreme weather-related
reliability concerns. We recognize that a proposal by a planning entity
to increase its interregional transfer capability to address the impact
of extreme heat and cold conditions on its portion of the Bulk-Power
System may be acceptable in a corrective action plan, and we expect
that the benchmark planning cases developed, and wide-area studies
conducted under this Standard could be beneficial for purposes of
determining interregional transfer needs. However, we decline to set a
minimum interregional transfer capability requirement in this
proceeding and note the Commission's ongoing pending proceeding
addressing such a requirement in Docket No. AD23-3.
    163. Regarding Idaho Power's concern given the amount of time
necessary to build new transmission,\264\ we note that corrective
action plans address deficiencies identified in a long-term
transmission planning timeframe (i.e., six to ten years and beyond).
The period associated with a transmission project will inform whether
and when that project may be included in an extreme weather corrective
action plan. For example, a transmission project that is not expected
to be operational in the six-to-ten-year long-term horizon may not be
relied upon in an extreme weather corrective action plan to mitigate
identified system deficiencies within that time horizon. In that
circumstance, the responsible entity will have to develop an extreme
weather corrective action plan that includes other measures that can be
implemented to ensure Reliable Operation of its portion of the Bulk-
Power System.
---------------------------------------------------------------------------

    \264\ Idaho Power Comments at 4, 6.
---------------------------------------------------------------------------

    164. With respect to concerns that generation capacity is not
appropriately included in corrective because it should be addressed
through resource adequacy processes, we reiterate our findings above in
section IV.F that the purpose of the new or modified Standard is to
address transmission system deliverability and not to supplant or
duplicate resource adequacy processes. With respect to concerns from
PIOs and ACP that generation may be ineffective as a mitigation
measure, we note that responsible entities have the flexibility to
determine the appropriate mitigation measure for their circumstances.
d. Notification to Applicable Regulatory Authorities or Governing
Bodies Responsible for Retail Electric Service Issues
    165. We direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans
with, and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues. We
agree with commenters that relevant state entities should have the
opportunity to provide input during the

development of corrective action plans. Just as this final rule seeks
to ensure Reliable Operation of the Bulk-Power System during extreme
heat and cold weather events, regulatory authorities and governing
bodies responsible for retail electric service are taking actions to
ensure reliability for local stakeholders. As such, we believe that
requiring responsible entities to seek input from applicable regulatory
authorities or governing bodies responsible for retail electric service
issues when developing corrective action plans could help ensure that
shared opportunities to increase system reliability are not missed.
Further, as NESCOE points out, such consultation may allow these
entities to better understand ``the cost implications of various
approaches'' and, therefore, provide ``better insight into the
considerations and tradeoffs inherent in the options available.'' \265\
---------------------------------------------------------------------------

    \265\ NESCOE Comments at 4.
---------------------------------------------------------------------------

    166. We also agree with NESCOE that sharing corrective action plans
with applicable regulatory authorities or governing bodies responsible
for retail electric service is necessary given the possibility that
corrective action plans could include load shedding.\266\ As the
Commission has stated in the past, we believe that the public should
have notice and understanding of a responsible entity's plans to shed
non-consequential load.\267\ Therefore, just as Reliability Standard
TPL-001-5.1 requires planning coordinators and transmission planners to
notify stakeholders, including applicable regulatory authorities or
governing bodies responsible for retail electric service, of their
intent to include non-consequential load loss in corrective action
plans for certain single-contingency events,\268\ the new or modified
Reliability Standard must also require responsible entities to
similarly communicate their intent to use non-consequential load shed
in their extreme weather corrective action plans.
---------------------------------------------------------------------------

    \266\ Id. at 5.
    \267\ Transmission Planning Reliability Standards, Order No.
762, 77 FR 26686 (May 7, 2012), 139 FERC ] 61,060, at P 65 (2012).
    \268\ Reliability Standard TPL-001-5.1, at attach. 1.
---------------------------------------------------------------------------

    167. Further, because an important goal of transmission planning is
to avoid load shed,\269\ any responsible entity that includes non-
consequential load loss in its corrective action plan should also
identify and share with applicable regulatory authorities or governing
bodies responsible for retail electric service alternative corrective
actions that would, if approved and implemented, avoid the use of load
shedding. Examples could include building additional generation and/or
transmission capacity, energy efficiency programs, and demand load
response programs.\270\
---------------------------------------------------------------------------

    \269\ Order No. 693, 118 FERC ] 61,218 at P 1,795.
    \270\ To be clear, responsible entities may also pursue such
mitigating actions in the first instance, subject to the approval of
relevant regulatory authorities. See supra P 161.
---------------------------------------------------------------------------

    168. While we direct NERC to require registered entities to
communicate the results of their studies and share their extreme
weather corrective action plans with applicable regulatory authorities
or governing bodies responsible for retail electric service, NERC
should not attempt to mandate that entities which are not under the
Commission's jurisdiction participate in the development of corrective
action plans.

I. Other Extreme Weather-Related Events and Issues

    169. While the NOPR focused on extreme heat and cold weather
events, the NOPR recognized that long-term drought, particularly when
occurring in conjunction with high temperatures, could also pose a
serious risk to Bulk-Power System reliability over a wide geographical
area. In the NOPR, the Commission raised a concern that drought may
cause or contribute to conditions that affect reliable operation of the
Bulk-Power System such as transmission outages, reduced plant
efficiency, and reduced generation capacity. The Commission sought
comment on whether drought should be included along with extreme heat
and cold weather events within the scope of the Reliability
Standard.\271\ Additionally, the Commission invited comment on whether
other extreme events with significant impact on the reliability of the
Bulk-Power System could also be considered and modeled in the
future.\272\
---------------------------------------------------------------------------

    \271\ NOPR, 179 FERC ] 61,195 at P 92.
    \272\ Id. P 93.
---------------------------------------------------------------------------

1. Comments
    170. Indicated Trade Associations, EDF, and ACP support including
the consideration of drought with extreme heat and cold weather events
within the scope of the new or modified Reliability Standard.\273\ NERC
agrees, suggesting that drought conditions be studied in drought-prone
areas of the country.\274\ EDF notes that drought events can
significantly impact the capacity and operation of water-cooled fossil
and nuclear generators and other water-cooled assets, as well as
hydroelectric generators. EDF also asserts that drought events are also
highly correlated with high temperature and wildfires. Therefore,
according to EDF, a failure to consider drought impacts could result in
an overestimation of generation availability during an extreme heat
weather event and understate the risks of that event.\275\
---------------------------------------------------------------------------

    \273\ Indicated Trade Associations Comments at 13; EDF Comments
at 19; ACP Comments at 18-19.
    \274\ NERC Comments at 12.
    \275\ EDF Comments at 24.
---------------------------------------------------------------------------

    171. Similarly, Indicated Trade Associations note that they support
the study of long-term drought impacts on relevant generation (e.g.,
hydro-electric, geothermal, and nuclear generation) in regions where
drought has been, or may plausibly become, an issue. They add that
droughts are sustained long-term conditions that may be fundamentally
studied and addressed differently--for example, as a fuel supply
sensitivity--than a short-term extreme heat or cold weather event.\276\
However, Indicated Trade Associations believe that the Commission
should not attempt to address all types of extreme weather events at
once in the Reliability Standard, but rather take a phased
approach.\277\
---------------------------------------------------------------------------

    \276\ Indicated Trade Associations Comments at 13.
    \277\ Id.
---------------------------------------------------------------------------

    172. ACP states ``[b]ecause drought events are already widespread
across all regions, and climate change will make them even more
frequent and widespread, it would be prudent for the Commission and
NERC to require all regions to include drought in their analysis of
severe weather benchmark events under TPL-001.'' \278\
---------------------------------------------------------------------------

    \278\ ACP Comments at 10.
---------------------------------------------------------------------------

    173. Tri-State notes that drought is already sufficiently included
in the resource forecasts developed by Resource Planners.\279\
---------------------------------------------------------------------------

    \279\ Tri-State Comments at 8.
---------------------------------------------------------------------------

    174. Certain commenters support the inclusion of extreme weather
events beyond heat, cold and drought. For example, NERC identifies
extreme weather conditions for inclusion in required studies, such as
high winds, diminished winds, dust, smoke, fog, and increased cloud
cover.\280\ According to NERC, such long-term, widespread weather and
environmental conditions can impact resource availability and the
transmission system. Other commenters suggest the inclusion of other
extreme weather events such as wildfires, hurricanes, and tornadoes;
\281\ rain and wind (including derechos), and ice storms; \282\ debris
flow (landslide risk following wildfire scars and heavy

precipitation) and rain-on-snow events that may lead to dam
overtopping.\283\
---------------------------------------------------------------------------

    \280\ NERC Comments at 12.
    \281\ EDF Comments at 25.
    \282\ AEP Comments at 5.
    \283\ SCE Comments at 6-7.
---------------------------------------------------------------------------

    175. EPRI points out that certain extreme weather events such as
hurricanes or flooding can and do often occur independent of extreme
heat and cold events. As such, EPRI states that the standard should
identify climate and weather-related threats that occur concurrently or
independently based on the planning area's local footprint and develop
scenarios accordingly.\284\
---------------------------------------------------------------------------

    \284\ EPRI Comments at P 29.
---------------------------------------------------------------------------

    176. In contrast, MISO and LCRA comment that the Reliability
Standard should be limited to extreme heat and cold events. MISO also
comments that there is a fundamental difference between extreme heat
and cold events and other extreme weather events: extreme temperature
events would likely result in the load increasing and continuing to
stay online, while other extreme weather events such as hurricanes or
tornados create the possibility of load loss. MISO also points out that
the operation horizon will continue to prepare for situations like
hurricanes, tornados, or ice storms.\285\ Likewise, LCRA adds that
drought and other extreme weather events beyond extreme temperature are
already modeled by existing extreme event contingencies.\286\
---------------------------------------------------------------------------

    \285\ MISO Comments at 2.
    \286\ LCRA Comments at 4.
---------------------------------------------------------------------------

2. Commission Determination
    177. We decline to direct NERC to create or modify a Reliability
Standard to specifically require the assessment of the impacts of
drought conditions as part of extreme heat and cold transmission system
planning. As explained above, the type of long-term meteorological
study involved in extreme heat and cold event transmission planning
necessarily includes examining the extreme weather impact on base
climate conditions over the study period, conditions that would have to
include anticipated drought conditions in relevant planning areas.\287\
---------------------------------------------------------------------------

    \287\ See supra P 114
---------------------------------------------------------------------------

    178. We agree with various commenters that drought conditions may
impact reliability,\288\ and drought impacts on generation are already
studied in the resource forecasts developed by resource planners and
mitigated by operating procedures. Additionally, droughts that may
occur concurrently with extreme heat and cold events will be included
in the benchmark planning case, as drought conditions would be present
in the meteorological data that feeds the benchmark planning case,\289\
and the possibility of more severe drought could be reflected as part
of a sensitivity analysis.\290\
---------------------------------------------------------------------------

    \288\ See e.g., EDF Comments at 24.
    \289\ See supra note 155.
    \290\ See supra P 114 and note 155.
---------------------------------------------------------------------------

    179. Regarding other extreme weather events such as NERC's concern
with high winds, diminished winds, dust, smoke, smog fog, extreme
snowstorms, flooding and increased cloud cover, and extreme snowstorms,
or other commenters recommendations to include hurricanes, tornados,
heavy rain and wind, and ice storms; and adjacent events such as
wildfires, debris flow, and flooding, we agree that these conditions
may affect the Bulk-Power System. However, we are not persuaded that a
directive to address these events in the new or modified Reliability
Standard is warranted at this time.
    180. As MISO indicates, there are fundamental differences between
extreme heat and cold events and other extreme weather events that cast
doubt as to whether this Reliability Standard is the correct vehicle
for addressing their impacts.\291\ For instance, extreme heat and cold
events generally affect large geographic areas, while other extreme
weather and adjacent events such as tornadoes, hurricanes, storms,
floods, and wildfires tend to have more localized impacts. Moreover, as
MISO points out, extreme heat and cold weather events are typically
characterized by potential sustained load increases, while other
extreme weather events typically result in load losses.
---------------------------------------------------------------------------

    \291\ MISO Comments at 2.
---------------------------------------------------------------------------

J. Reliability Standard Development and Implementation Timeline

    181. The Commission proposed to direct NERC to develop a new or
modified Reliability Standard within one year of the effective date of
a final rule in this proceeding, with compliance obligations beginning
no later than 12 months from Commission approval of the proposed
Reliability Standard.\292\
---------------------------------------------------------------------------

    \292\ NOPR, 179 FERC ] 61,195 at P 48.
---------------------------------------------------------------------------

1. Comments
    182. NERC raises no concerns with the proposed 12-month proposal to
create a new or modified Reliability Standard; however, NERC requests
that the Commission consider coordinating the timing of this final rule
to allow NERC to benefit from the informational filings in Docket Nos.
RM22-16-000 and AD21-13-000, as information obtained from these reports
``may prove useful to the NERC standard development process.'' \293\
---------------------------------------------------------------------------

    \293\ NERC Comments at 14. In Docket Nos. RM22-16-000 and AD21-
13-000, the Commission proposes directing transmission providers to
submit one-time informational reports describing their current or
planned policies and processes for conducting extreme weather
vulnerability assessments. One-Time Informational Reports on Extreme
Weather Vulnerability Assessments; Climate Change, Extreme Weather,
& Elec. Sys. Reliability, Notice of Proposed Rulemaking, 87 FR 39414
(July 1, 2022), 179 FERC ] 61,196 (2022) (Informational Reports
NOPR).
---------------------------------------------------------------------------

    183. PJM and MISO Transmission Owners state that one year will not
be enough time to develop the proposed Reliability Standard.\294\ PJM
states that such a short timeframe will hamper stakeholder input.\295\
PJM further comments that the NOPR's proposed timeline for standard
development is not ``sequenced with any of the other activities
associated with ensuring enhanced reliability planning'' and will thus
``divert resources from the more comprehensive work that is needed in
this area.'' \296\ MISO Transmission Owners agree that ``one year's
time is not long enough'' to modify or create a new Reliability
Standard, and the Commission should give NERC ``more time.'' \297\
---------------------------------------------------------------------------

    \294\ PJM Comments at 14; MISO Transmission Owners Comments at
7.
    \295\ PJM Comments at 14.
    \296\ Id.
    \297\ MISO Transmission Owners Comments at 7.
---------------------------------------------------------------------------

    184. Regarding the effective date of any resulting Reliability
Standard, NERC requests that the Commission clarify the proposed
implementation schedule, i.e., ``whether entities must begin to comply
with all new study requirements within one year of Commission approval
(i.e., completed studies with Corrective Action Plans developed), or
whether a phased-in approach beginning no later than one year is
permitted for entities to coordinate on the development of new models,
collect new data, and perform the necessary coordination to study wide
area impacts before completing studies and developing any associated
Corrective Action Plans.'' \298\
---------------------------------------------------------------------------

    \298\ NERC Comments at 14-15.
---------------------------------------------------------------------------

    185. PJM also states that one year is not enough time for
responsible entities to implement the new or revised Reliability
Standard, because after Commission approval ``Transmission Providers
like PJM will have responsibility to translate it into workable
planning process methodologies and related stakeholder-approved manual
language.'' \299\
---------------------------------------------------------------------------

    \299\ PJM Comments at 14-15.
---------------------------------------------------------------------------

    186. PJM further calls for flexibility on setting start dates for
the implementation period for different

entities given variances in regional planning cycles.\300\ APS echoes
the call for flexibility as to the timeframe for developing a
corrective action plan as the potential mitigation strategies may vary
or include neighboring entities.\301\
---------------------------------------------------------------------------

    \300\ Id.
    \301\ APS Comments at 8.
---------------------------------------------------------------------------

    187. AEP proposes that the Commission provide responsible entities
``at least two years to implement stability analysis'' after the
proposed Reliability Standard takes effect, and that corrective action
plans be developed ``within one year of the assessment of reliability
deficiency.'' \302\
---------------------------------------------------------------------------

    \302\ AEP Comments at 13, 24.
---------------------------------------------------------------------------

2. Commission Determination
    188. We direct NERC to submit a new or modified Reliability
Standard within 18 months of the date of publication of this final rule
in the Federal Register. Further, we direct NERC to propose an
implementation timeline for the new or modified Reliability Standard,
with implementation beginning no later than 12 months after the
effective date of a Commission order approving the proposed Reliability
Standard.
    189. We agree with NERC that it is important to coordinate the
timeline for the development of a Reliability Standard under this
proceeding with that of the extreme weather one-time informational
reports required under Docket Nos. RM22-16-000 and AD21-13-000.\303\
The Informational Reports Final Rule, which is being issued
concurrently with this final rule, directs responsible entities to
develop and file with the Commission within 120 days of that order's
publication in the Federal Register a one-time informational report
``describing their current or planned policies and processes for
conducting extreme weather vulnerability assessments.'' \304\ The
Informational Reports Final Rule further states that public comments
will be due 60 days after the reports are filed.\305\ These
informational reports may assist the standard drafting team's efforts
in developing the proposed Reliability Standard, as they will be
helpful for determining whether and to what extent transmission
providers are already considering the impacts of extreme weather
events. We believe that extending the NOPR's proposed standard
development timeline is appropriate to ensure that NERC can benefit
from the information obtained from these reports, as well as from
public comments on the reports.
---------------------------------------------------------------------------

    \303\ Final Rule, Order No. 897, 183 FERC ] 61,192 (2023)
(``Informational Reports Final Rule'').
    \304\ Id. PP 1, 3.
    \305\ Id. P 104.
---------------------------------------------------------------------------

    190. With regards to PJM and MISO Transmission Owners' comments, we
recognize that the NOPR proposed an ambitious development timeline for
the proposed Reliability Standard. As we indicated in the NOPR, the
negative impact of extreme weather on the reliability of the Bulk-Power
System demands an urgent response. Further, we note that NERC, the
entity responsible for the development of the Reliability Standard, did
not raise concerns about the NOPR's proposed development timeline. As
such, we are not persuaded that there is a present need to extend the
deadline to submit a proposed Reliability Standard further than what is
necessary to ensure that NERC can benefit from the data obtained as a
result of the one-time informational reports.
    191. Accordingly, we direct NERC to submit a proposed Reliability
Standard within 18 months of the date of publication of this final rule
in the Federal Register. We believe that extending the development
timeline by six months should be sufficient to ensure that the standard
drafting team will be able to take advantage of the one-time reports
required by the Commission under Docket Nos. RM22-16-000 and AD21-13-
000.
    192. We decline to direct NERC to ensure that entities fully comply
with all new requirements within one year of Commission approval (i.e.,
completed studies with corrective action plans developed). As AEP and
PJM note in their comments, the new or modified Reliability Standard
will require significant implementation efforts. Given the complexities
and multiple stages of activity that would be involved in compliance
with the directives in this final rule, we believe that a more flexible
implementation approach is appropriate.
    193. We therefore direct NERC to establish an implementation
timeline for the proposed Reliability Standard. In complying with this
directive, NERC will have discretion to develop a phased-in
implementation timeline for the different requirements of the proposed
Reliability Standard (i.e., developing benchmark cases, conducting
studies, developing corrective action plans). However, this phased-in
implementation must begin within 12 months of the effective date of a
Commission order approving the proposed Reliability Standard and must
include a clear deadline for implementation of all requirements.

V. Information Collection Statement

    194. The information collection requirements contained in this
final rule are subject to review by the Office of Management and Budget
(OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\306\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\307\ Upon approval of
a collection of information, OMB will assign an OMB control number and
expiration date. Respondents subject to the filing requirements of this
rule will not be penalized for failing to respond to this collection of
information unless the collection of information displays a valid OMB
control number.
---------------------------------------------------------------------------

    \306\ 44 U.S.C. 3507(d).
    \307\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    195. The directives to NERC to develop a new Reliability Standard
or modify existing Reliability Standard TPL-001 (Transmission System
Planning Performance Requirements), are covered by, and already
included in, the existing OMB-approved information collection FERC-725
(Certification of Electric Reliability Organization; Procedures for
Electric Reliability Standards; OMB Control No. 1902-0225), under
Reliability Standards Development.\308\ The reporting requirements in
FERC-725 include the ERO's overall responsibility for developing
Reliability Standards, such as the TPL-001 Reliability Standard, which
is designed to ensure the Bulk-Power System will operate reliably over
a broad spectrum of system conditions and following a wide range of
probable contingencies.\309\ The Commission will submit to OMB a
request for a non-substantive revision of FERC-725 in connection with
this final rule.
---------------------------------------------------------------------------

    \308\ Reliability Standards Development as described in FERC-725
covers standards development initiated by NERC, the Regional
Entities, and industry, as well as standards the Commission may
direct NERC to develop or modify. The information collection
associated with this final rule ordinarily would be a non-material
addition to FERC-725. However, an information collection request
unrelated to this final rule is pending review under FERC-725 at the
Office of Management and Budget. To submit this final rule timely to
OMB, we will submit this to OMB as a temporary placeholder under
FERC-725(1A), OMB Control No. 1902-0289.
    \309\ Reliability Standard TPL-001-4, Purpose.
---------------------------------------------------------------------------

VI. Environmental Analysis

    196. 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.\310\ The Commission has categorically excluded certain
actions from this requirement as not having a significant effect on the
human environment. Included in the exclusion are rules that are
clarifying, corrective, or procedural or that do not substantially
change the effect of the regulations being amended.\311\ The actions
directed here fall within this categorical exclusion in the
Commission's regulations.
---------------------------------------------------------------------------

    \310\ Regul. Implementing the Nat'l Env't Pol'y Act, Order No.
486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ] 30,783
(1987) (cross-referenced at 41 FERC ] 61,284).
    \311\ 18 CFR 380.4(a)(2)(ii) (2022).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    197. The Regulatory Flexibility Act of 1980 (RFA) \312\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \312\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

    198. This final rule directs NERC, the Commission-certified ERO, to
develop a new or modified Reliability Standard that requires long-term
transmission system planning designed to prepare for extreme heat and
cold weather events. Therefore, this final rule will not have a
significant or substantial impact on entities other than NERC.
Consequently, the Commission certifies that this final rule will not
have a significant economic impact on a substantial number of small
entities.
    199. Any Reliability Standards proposed by NERC in compliance with
this rulemaking will be considered by the Commission in future
proceedings. As part of any future proceedings, the Commission will
make determinations pertaining to the Regulatory Flexibility Act based
on the content of the Reliability Standards proposed by NERC.

VIII. Document Availability

    200. 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 the Commission's Home Page (http://www.ferc.gov). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
    201. 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.
    202. User assistance is available for eLibrary and the FERC's
website during normal business hours from FERC Online Support at (202)
502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
[email protected].

IX. Effective Date and Congressional Notification

    203. This rule will become effective September 21, 2023. 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.

By the Commission. Commissioner Danly is concurring in part.
    Issued: June 15, 2023.
Debbie-Anne A. Reese,
Deputy Secretary.

    The following appendix will not appear in the Code of Federal
Regulations.

Appendix A: Commenter Names

----------------------------------------------------------------------------------------------------------------
                  Acronyms                                              Commenter name
----------------------------------------------------------------------------------------------------------------
ACP.........................................  American Clean Power Association.
ACEG........................................  Americans for a Clean Energy Grid.
AEP.........................................  American Electric Power Service Corporation.
Ampjack.....................................  Ampjack Industries Ltd.
APS.........................................  Arizona Public Service Company.
BPA.........................................  Bonneville Power Administration.
EDF.........................................  Environmental Defense Fund.
Indicated Trade Associations................  The Edison Electric Institute (EEI), the American Public Power
                                               Association (APPA), the Large Public Power Council (LPPC), the
                                               National Rural Electric Cooperative Association (NRECA), and the
                                               Transmission Access Policy Study Group (TAPS).
Entergy.....................................  Entergy Services, LLC.
EPRI........................................  Electric Power Research Institute.
EPSA........................................  Electric Power Supply Association.
ERCOT.......................................  Electric Reliability Council of Texas, Inc.
Eversource..................................  Eversource Energy Service Company.
Idaho Power.................................  Idaho Power Company.
ISO-NE......................................  ISO New England Inc.
LCRA........................................  LCRA Transmission Services Corporation.
Louisiana PSC...............................  Louisiana Public Service Commission.
MISO........................................  Midcontinent Independent System Operator, Inc.

MISO Transmission Owners....................  Ameren Services Company, as agent for Union Electric Company d/b/a
                                               Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois
                                               and Ameren Transmission Company of Illinois; American
                                               Transmission Company LLC; Big Rivers Electric Corporation;
                                               Central Minnesota Municipal Power Agency; City Water, Light &
                                               Power (Springfield, IL); Cleco Power LLC; Cooperative Energy;
                                               Dairyland Power Cooperative; Duke Energy Business Services, LLC
                                               for Duke Energy Indiana, LLC; East Texas Electric Cooperative;
                                               Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy
                                               Mississippi, LLC; Entergy New Orleans, LLC; Entergy Texas, Inc.;
                                               Great River Energy; GridLiance Heartland LLC; Hoosier Energy
                                               Rural Electric Cooperative, Inc.; Indiana Municipal Power Agency;
                                               Indianapolis Power & Light Company; International Transmission
                                               Company d/b/a ITCTransmission; ITC Midwest LLC; Lafayette
                                               Utilities System; Michigan Electric Transmission Company, LLC;
                                               MidAmerican Energy Company; Minnesota Power (and its subsidiary
                                               Superior Water, L&P); Missouri River Energy Services; Montana-
                                               Dakota Utilities Co.; Northern Indiana Public Service Company
                                               LLC; Northern States Power Company, a Minnesota corporation, and
                                               Northern States Power Company, a Wisconsin corporation,
                                               subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric
                                               Company; Otter Tail Power Company; Prairie Power, Inc.; Republic
                                               Transmission, LLC; Southern Illinois Power Cooperative; Southern
                                               Indiana Gas & Electric Company (d/b/a CenterPoint Energy Indiana
                                               South); Southern Minnesota Municipal Power Agency; Wabash Valley
                                               Power Association, Inc.; and Wolverine Power Supply Cooperative,
                                               Inc.
NARUC.......................................  National Association of Regulatory Utility Commissioners.
NERC........................................  North American Electric Reliability Corporation.
NESCOE......................................  New England States Committee on Electricity.
NMA.........................................  National Mining Association.
NYISO.......................................  New York Independent System Operator, Inc.
NYSRC.......................................  New York State Reliability Council.
Ohio FEA....................................  Federal Energy Advocate for the Public Utilities Commission of
                                               Ohio.
PG&E........................................  Pacific Gas and Electric Company.
PIOs........................................  Public Interest Organizations (Sustainable FERC Project, Natural
                                               Resources Defense Council, American Council on Renewable Energy,
                                               Sierra Club, Southern Environmental Law Center, Western Resource
                                               Advocates).
PJM.........................................  PJM Interconnection, L.L.C.
SCE.........................................  Southern California Edison Company.
Sunflower...................................  Sunflower Electric Power Corporation.
Tri-State...................................  Tri-State Generation and Transmission Association, Inc.
UCS.........................................  Union of Concerned Scientists.
WATT........................................  Working for Advanced Transmission Technologies.
WE ACT......................................  WE ACT for Environmental Justice.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2023-13286 Filed 6-22-23; 8:45 am]
BILLING CODE 6717-01-P