sufficient generation of the correct type to ensure resource adequacy
and system reliability. We cannot blame our problems on the weather.
The problem is federal and state policies which, by mandate or subsidy,
spur the development of weather dependent generation resources at the
expense of the dispatchable resources needed for system stability and
resource adequacy. This is seen in particularly stark terms in our
markets in which subsidies, combined with failed market design, warp
price signals. This destroys the incentives required to ensure the
orderly entry, exit, and retention of the necessary quantities of the
necessary types of generation. The thinner and thinner margins that
result render the Bulk-Power System more and more susceptible to the
caprices of weather. We have been warned by credible sources on the
matter: NERC,\133\ the RTOs,\134\ and Commission staff.\135\
---------------------------------------------------------------------------

    \132\ See Chairman Glick (@RichGlickFERC), Twitter (May 19,
2022, 11:13 a.m.), https://twitter.com/RichGlickFERC/status/1527306459263881223?s=20&t=3a4C-1cac3nmFkjZyvoUDA (``Extreme weather
may be the single most important factor impacting #grid #reliability
& the impacts of expected heat, drought, wildfires, hurricanes, &
other events--all pose a big threat. Keeping eye on West, ERCOT, &
parts of MISO this summer.''); Benjamin Mullin, Climate Change is
Straining California's Energy System, Officials Say, N.Y. Times (May
6, 2022), https://www.nytimes.com/2022/05/06/business/energy-environment/california-electricity-shortage.html.
    \133\ See generally North American Electric Reliability Corp.,
2022 Summer Reliability Assessment (May 2022), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments %20DL/NERC_SRA_2022.pdf. In
addition, NERC has warned that system operators in areas of
significant amounts of solar photovoltaic (PV) resources should be
aware of the potential for resource loss events during grid
disturbances. Id. at 6. NERC has further warned that ``[i]ndustry
experience with unexpected tripping of [Bulk-Power System]-connected
solar PV generation units can be traced back to the 2016 Blue Cut
fire in California, and similar events have occurred as recently as
Summer 2021. A common thread with these events is the lack of
inverter-based resource (IBR) ride-through capability causing a
minor system disturbance to become a major disturbance. The latest
disturbance report reinforces that improvements to NERC Reliability
Standards are needed to address systemic issues with IBRs.'' Id.
NERC also explains that ``because the electrical output of variable
energy resources (e.g., wind, solar) depends on weather conditions,
on-peak capacity contributions are less than nameplate capacity.''
Id. at 45.
    \134\ See, e.g., California Independent System Operator Corp.,
2022 Summer Loads and Resources Assessment (May 18, 2022), http://www.caiso.com/Documents/2022-Summer-Loads-and-Resources-Assessment.pdf; Midcontinent Independent System Operator (MISO),
Lack of Firm generation may necessitate increased reliance on
imports and use of emergency procedures to maintain reliability
(Apr. 28, 2022), https://www.misoenergy.org/about/media-center/miso-projects-risk-of-insufficient-firm-generation-resources-to-cover-peak-load-in-summer-months/; PJM Interconnection, L.L.C. (PJM),
Energy Transition in PJM: Frameworks for Analysis (Dec. 15, 2021),
https://pjm.com/-/media/committees-groups/committees/mrc/2021/20211215/20211215-item-09-energy-transition-in-pjm-whitepaper.ashx
(addressing renewable integration).
    \135\ See Staff Presentation on 2022 Summer Energy Market and
Reliability Assessment (AD06-3-000), FERC, at slide 9 (May 19,
2022), https://www.ferc.gov/news-events/news/presentation-report-2022-summer-energy-market-and-reliability-assessment (identifying
the Western U.S., Texas, MISO and Southwest Power Pool as ``[p]arts
of North America are at elevated or high risk of energy shortfalls
during peak summer conditions'') (emphasis in original); id. at
slide 10 (In MISO, ``[g]eneration capacity declined 2.3% since 2021
resulting in [a] lower reserve margin'' and the ``[n]orth and
central areas [are] at risk of reserve shortfall in extreme
temperatures, high generation outages, or low wind'' with ``[s]ome
risk of insufficient operating reserves at normal peak demand.'').
---------------------------------------------------------------------------

    3. As more nuclear \136\ and coal plants \137\--with their high
capacity factors and onsite fuel--announce early retirements, the
dispatchable resources that remain are predominantly natural gas
generators. Backstopping weather-dependent resources with gas
generators, largely dependent on just-in-time delivery of gas, raises
its own set of reliability concerns, particularly in areas--like New
England--with inadequate pipeline infrastructure. On top of this, the
Commission has delayed the processing of pipeline certificates and cast
a chill over the pipeline industry with its ``draft policy statements''
\138\ and orders throwing the finality of fully litigated certificates
into doubt.\139\ Under pressure to reduce emissions at all costs,
pipelines have moved to electrify compressor stations, furthering an
unhealthy co-dependency between the gas and electric systems. And the
efforts of politically motivated financial institutions to cut fossil
fuel producers' access to capital has added to the current supply
crunch.\140\ Yet, we are led to believe that extreme weather is
supposed to be the culprit for the nation's looming reliability woes.
Not so.
---------------------------------------------------------------------------

    \136\ U.S. Energy Information Administration, U.S. nuclear
electricity generation continues to decline as more reactors retire
(Apr. 8, 2022), https://www.eia.gov/todayinenergy/detail.php?id=51978.
    \137\ Ethan Howland, Coal plant owners seek to shut 3.2 GW in
PJM in face of economic, regulatory and market pressures, Utility
Dive (Mar. 22, 2022), https://www.utilitydive.com/news/coal-plant-owners-seek-to-retire-power-in-pjm/620781/.
    \138\ See Certification of New Interstate Nat. Gas Facilities,
178 FERC ] 61,107 (2022) (Danly and Christie, Comm'rs, dissenting));
Consideration of Greenhouse Gas Emissions in Nat. Gas Infrastructure
Project Revs., 178 FERC ] 61,108 (2022) (Danly and Christie,
Comm'rs, dissenting); see also Certification of New Interstate Nat.
Gas Facilities, 178 FERC ] 61,197, at P 2 (2022) (converting the two
policy statements to ``draft policy statements''). It is worth
noting that PJM and MISO filed comments on the draft policy
statements. PJM and MISO May 25, 2022 Limited Reply Comments, Docket
Nos. PL18-1-001 and PL21-3-001, at 4 (``[A]ny future Commission
pipeline policy should consider the importance of ensuring that
needed pipeline infrastructure can be timely sited, and ensure that
the need for infrastructure to meet electric system reliability is
affirmatively considered and not lost in the debate over the scope
of environmental reviews to be undertaken by the Commission.'').
    \139\ See, e.g., Algonquin Gas Transmission, LLC, 174 FERC ]
61,126 (2021) (Danly and Christie, Comm'rs, dissenting).
    \140\ Matt Egan, Energy crisis will set off social unrest,
private-equity billionaire warns, CNN Business (Oct. 26, 2021),
https://edition.cnn.com/2021/10/26/business/gas-prices-energy-crisis-schwarzman/index.html (``Part of the problem, [Blackstone CEO
Stephen Schwarzman] said, is that it's getting harder and harder for
fossil fuel companies to borrow money to fund their expensive
production activities, especially in the United States. And without
new production, supply won't keep up.'').
---------------------------------------------------------------------------

    4. The question of whether the weather is getting worse is a red
herring. The much more relevant question is whether current system
operations and tariff and market design are adequate to maintain
reliability. The present high risk of reliability failures proves that
they are not. That the policies of the Commission and other government
bodies are undermining reliability is far more obvious than the
question of whether, and how, the weather is getting worse and what
specific effects that worsening weather might have on the stability of
the electric system. That question of the weather's effect on
reliability is a subject that doubtless merits study and planning, but
misguided government policies are the root cause of the alarming
reliability issues facing the nation, not the weather.
    For these reasons, I respectfully concur.

-----------------------------------------------------------------------
James P. Danly,

Commissioner.
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Transmission System Planning Performance Requirements for Extreme
Weather
Docket No. RM22-10-000
(Issued June 16, 2022)
    CLEMENTS, Commissioner, concurring:
    1. Today's Notice of Proposed Rulemaking (NOPR) is an important
step to ensure that the North American Electric Reliability Corporation
(NERC) builds upon existing practices to better account for extreme
weather in transmission system planning. Together with the Notice of
Proposed Rulemaking proposing to direct transmission providers to
submit informational reports describing their current or planned
policies and processes for conducting extreme weather vulnerability
assessments,\1\ it will facilitate steps to enhance the reliability of
the electric system.
---------------------------------------------------------------------------

    \1\ One Time Informational Reports on Extreme Weather
Vulnerability Assessments, 179 FERC ] 61,196 (2022).
---------------------------------------------------------------------------

    2. NERC already addresses extreme weather in several ways. For
example, Reliability Standard TPL-001-4 requires planning coordinators
and transmission planners to conduct an analysis of extreme weather
events and

evaluate potential actions for reducing the likelihood or mitigating
the consequences of the event creating adverse impacts.\2\ NERC also
recently adopted Cold Weather Reliability Standards, which require
generators to prepare and implement plans for cold weather, and require
the exchange of information between the balancing authority,
transmission operator, and reliability coordinator about the
generator's ability to operate under cold weather conditions to ensure
grid reliability.\3\ Further, NERC has prioritized improving bulk
electric system resilience to wide-spread long-term extreme temperature
events in its 2022 Enterprise Work Plan,\4\ and is pursuing
enhancements to reliability standards for the operational planning
timeframe to address extreme weather via its Energy Reliability
Assessment Task Force.\5\ Yet even with these actions, utilities and
grid operators remain underprepared for the changing climate and the
increasing frequency of extreme weather it is bringing, as is evident
in NERC's 2022 Summer Reliability Assessment. Therein, NERC highlights
the elevated risk of an energy emergency due to the increased demand
for electricity driven by above average temperatures combined with a
reduced capacity because extreme drought conditions threaten the
availability of hydroelectric energy for transfer.\6\ Had the nation's
utilities and grid operators better planned for climate change and the
attendant increased likelihood of these conditions, they would be
better prepared for the conditions we are likely to face this summer.
---------------------------------------------------------------------------

    \2\ Reliability Standard TPL-001-4; see also Notice of Proposed
Rulemaking, Transmission System Planning Performance Requirements
for Extreme Weather (Extreme Weather NOPR), 179 FERC ] 61,195, at PP
20-23 (2022) (discussing the requirements set forth in TPL-001-4).
    \3\ See Extreme Weather NOPR at PP 18-19 (discussing Cold
Weather Reliability Standards, 176 FERC ] 61,119, at PP 1, 3
(2021)).
    \4\ See NERC, 2022 ERO Enterprise Work Plan Priorities, at 3
(Nov. 4, 2021), available at nerc.com/AboutNERC/StrategicDocuments/ERO_2022_Work_Plan_Priorities_Board_Approved_Nov_4_2021.pdf.
    \5\ See NERC, DRAFT Energy Management Recommendations for Long
Duration Extreme Winter and Summer Conditions, available at https://www.nerc.com/comm/RSTC/ERATF/Combined-Energy-Management-Roadmap.pdf
(last accessed June 15, 2022).
    \6\ NERC, 2022 Summer Reliability Assessment, at 7, 9 (May
2022), available at https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_SRA_2022.pdf.
---------------------------------------------------------------------------

    3. There is no more urgent priority for this Commission than to
reform system planning so that it sufficiently contemplates and
provides mechanisms to address the impact of extreme weather events on
the electricity grid. Across geographies, regulatory regimes, regional
resource mixes and market designs, the impact of extreme weather has
vastly outpaced regulatory adaptation to it. So, I am glad to support
this priority by voting for today's NOPR, which complements NERC's
ongoing efforts to address the operational time frame and fills a gap
by ensuring that Reliability Standards better account for extreme
weather in planning. I write separately for two reasons.
    4. First, while it represents an important step in tackling extreme
weather's myriad impacts on the transmission system, strong follow
through from NERC will be required to ensure a reliability standard
that addresses extreme weather reliability challenges in a
comprehensive and cost-effective manner. While the proposed rule seeks
comments on whether drought should be included along with extreme heat
and cold weather events within the scope of Reliability Standard TPL-
001-5.1, I believe that what we already know about meteorological
projections and drought's anticipated impacts on the electricity system
compel the development of drought benchmark events in applicable
regions of the country.\7\ The question for me is not whether such
events should be included, but how TPL-001-5.1 should cover the impact
of drought induced reductions in supply on regions already experiencing
unprecedented reductions in reservoir supply and increased wildfire
risk. Further, NERC can facilitate cost effective implementation of
these reliability standard modifications by requiring modeling of
extreme weather events according to consistent planning rules,
providing for consultation with states and other regulators in the
development of corrective actions plans, and by considering of the
interaction between this proposed Reliability Standard and related
planning processes and rules, including the Commission's recently
issued notice of proposed rulemaking regarding long-term regional
transmission planning.\8\ I urge stakeholders to provide
recommendations to NERC as to how best to account for these
considerations in commenting on this proposal.
---------------------------------------------------------------------------

    \7\ See Extreme Weather NOPR at PP 90-92 (discussing the
anticipated impacts of drought on the electricity system); infra P
8.
    \8\ Building for the Future Through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, 179 FERC ] 61,028 (2022) (Regional Planning NOPR).
---------------------------------------------------------------------------

    5. Second, it is important to note that if we are to cost-
effectively ensure system reliability as the frequency and intensity of
extreme weather events continues to increase, further action is
necessary to complement today's initial proposal. We have learned a
good amount about the impact of extreme weather on the electricity
system the hard way.\9\ We have the opportunity to learn a great deal
more from the substantial amount of important information and good
ideas that stakeholders submitted in response to the Commission's
inquiry into Climate Change, Extreme Weather, and Electric System
Reliability in Docket No. AD21-13.
---------------------------------------------------------------------------

    \9\ Severe weather events have caused significant outages in the
past decade. See NOPR at P 26 (discussing February 2011 Southwest
Cold Weather Event where low temperatures caused uncontrolled
blackouts throughout ERCOT's entire region, effecting 4.4 million
electric customers), P 28 (discussing January 2014 Polar Vortex Cold
Weather Event where increased demand for gas and the unavailability
of gas-fired generation led to 35,000 MW of generator outages, and
PP 31-32 (describing how the 2021 Cold Weather Event brought the
largest controlled load shed in U.S. history, with more than 4.5
million people losing power, resulting in at least 210 people
dying).
---------------------------------------------------------------------------

    6. Themes that emerge from this collective experience and record
include, at least, the need to consider: (1) establishing a process for
setting explicit minimum interregional transfer capability requirements
or otherwise identifying least regrets interregional solutions, (2)
improved scheduling and coordination in non-RTO regions, and (3)
ensuring that planning and market mechanisms appropriately reflect
resource availability during extreme weather events, accounting for the
possibility of common mode failures or other correlated outages.\10\ As
I provide in more detail below, I urge my colleagues to prioritize
these complementary issues in the months to come.
---------------------------------------------------------------------------

    \10\ While this statement highlights key priority areas for
further inquiry, it is not intended to be exclusive. For instance,
while I do not discuss it in detail here, I support Commissioner
Phillips' call for an examination of whether the Commission should
require revisions to RTO/ISO generation and transmission outage
scheduling practices. See Extreme Weather NOPR (Phillips, Comm'r,
concurring) at PP 8-9.
---------------------------------------------------------------------------

A. Ensuring Cost-Effective Implementation of This NOPR

    7. The effectiveness of this NOPR depends upon NERC implementing it
in a manner that comprehensively addresses extreme weather threats,
provides for consistency in modeling scenarios and methods to the
greatest extent possible, facilitates consultation with state
regulators, and appreciates its interrelation with the Commission's
Regional Planning NOPR. I urge NERC and stakeholders to provide
feedback on the following issues, which may facilitate strengthening
the effectiveness of the eventual reliability standard.

    8. Initially, in addition to benchmark cases for extreme heat and
cold, it seems prudent to include drought within the scope of
Reliability Standard TPL-001-5.1. It is not surprising that, as noted
in comments in the extreme weather docket, the more frequent and severe
droughts occurring and expected to worsen in parts of the West and
Southwest portend potentially significant grid impacts via limitations
on hydroelectric generating facilities as well as thermal facilities
that require water for cooling.\11\ These drought conditions also, of
course, serve as a main driver of what the Oregon Public Utility
Commission describes as ``one of the most pressing and difficult
issues: the rapidly increasing risk of highly destructive wildfires.''
\12\ While the need to consider a drought benchmark case does not
currently arise in all regions of the country, failure to contemplate
the impacts of drought in relevant regions as part of equipping
transmission planning to effectively address extreme weather would
hamper a final Reliability Standard's impact.
---------------------------------------------------------------------------

    \11\ See, e.g., Comments of Environmental Defense Fund and
Columbia Law School Sabin Center for Climate Change Law, Docket No.
AD21-13, at 3 (filed Sept. 27, 2021) (``[C]hanges to the
availability of water for cooling at thermal power plants and for
hydroelectric generation will depart from historical patterns.'');
Comments of the California Independent System Operator, Docket No.
AD21-13 at 3 (filed April 15, 2021) (noting that drought already
``has affected the availability of hydroelectric facilitates in some
years'').
    \12\ Comments of the Oregon Public Utility Commission, Docket
No. AD21-13, at 2 (filed Apr. 14, 2021).
---------------------------------------------------------------------------

    9. Further, I am pleased to see the proposal's emphasis that ``it
is important that transmission planners and planning coordinators
likely to be impacted by the same types of extreme weather events use
consistent benchmark events.'' \13\ I urge NERC and stakeholders to
contemplate the benefits of consistent modeling practices and modeling
assumptions, and to provide feedback on how such consistency can best
be achieved within the scope of this proposed rule.\14\ Consistency in
the inputs and assumptions feeding these cases and scenarios will allow
for neighboring transmission planners and planning coordinators to work
together towards cost-effective corrective actions, like increasing
transfer capability, that could otherwise be missed for lack of apples-
to-apples comparisons.
---------------------------------------------------------------------------

    \13\ Extreme Weather NOPR at P 52.
    \14\ See Comments of the Institute for Policy Integrity Docket
No. AD21-13, at 8 (filed Apr. 14, 2021) (emphasizing potential
benefits of consistent modeling practices); see also Pre-Technical
Conference Comments of Exelon Corporation Docket No. AD21-13, at 14
(filed Apr. 15, 2021) (suggesting a process by which regulators and
experts could ``define a reasonable range of scenarios describing
potential climate-change related weather events and longer-term
climate patters over the coming decades'').
---------------------------------------------------------------------------

    10. In addition, I encourage NERC to set forth a process that
provides for consultation with states in the development of corrective
action plans, given that many components of such plans could be state
jurisdictional. As we see in other contexts, states' jurisdiction over
their resource mix and the Federal Power Act's separation of authority
between FERC and states means that consideration of some of the more
cost-effective options for corrective actions, including reducing
demand through energy efficiency and other demand side resource
development, cannot be properly facilitated without state
partnership.\15\ States' decisions regarding the siting of generation
and transmission facilities may also be impacted by extreme
weather.\16\ Consulting with states will both ensure that opportunities
for addressing reliability changes with state-jurisdictional solutions
are not missed, and provide a path to regulatory approval of such
solutions in a manner that ensures both FERC and state regulators are
informed of the costs and benefits of different corrective actions.\17\
High-level coordination would also allow for harmony between the
extreme weather modeling methods of states and those of NERC, such as
``referring to an agreed set of climate modeling parameters or
scenarios,'' where appropriate in developing their own solutions.\18\
---------------------------------------------------------------------------

    \15\ See Comments of PJM Interconnection, L.L.C. Docket No.
AD21-13, at 9 (filed Apr. 15, 2021) (``[C]oordination with states
(including state permitting agencies) on climate change and extreme
weather events [is] critical.''); Comments of the R Street Institute
Docket No. AD21-13, at 15 (filed Apr. 15, 2021) (``It is imperative
for future reliability policy to harmonize the actions of federal
and state authorities, at least to a basic degree.''); see also
Motion to Intervene and Comments of the National Association of
Regulatory Utility Commissioners Docket No. AD21-13, at 2 (filed
Apr. 14, 2021) (urging the Commission to confer with the states
``where climate change and extreme weather events may implicate both
federal and state issues'').
    \16\ See Comments of the National Rural Electric Cooperative
Association Docket No. AD21-13, at 13 (filed Apr. 15, 2021). See
also id. (``Most of the necessary decision-making and policy-
making'' with regard to extreme weather ``will be at state and local
levels.'').
    \17\ See Comments of the Institute for Policy Integrity, Docket
No. AD21-13, at 8 (filed Apr. 14, 2021) (coordination would
``facilitat[e] state efforts to encourage development of flexible
resources'').
    \18\ Id.
---------------------------------------------------------------------------

    11. Further, in considering how to address the aims of this
proposal cost effectively, it is important for NERC and stakeholders to
consider how this proposal to reform TPL-001-5.1 may interact with the
Commission's notice of proposed rulemaking on regional transmission
planning and cost allocation.\19\ That NOPR proposes to require
transmission planners to engage in probabilistic, scenario-based
planning for longer-term system needs, including at least one extreme
weather scenario, but exempts shorter-term reliability planning from
this scenario planning requirement. Since efficiencies are gained when
considering multiple drivers for new transmission investment and it is
likely that some amount of the corrective action that may emerge from
the new reliability standard involves regional or interregional
transmission development, it is important to derive stakeholders'
perspectives on how potential performance standards and corrective
actions under a revised reliability standard interact with both
shorter-term reliability and proposed longer term planning, both in
terms of consistency in planning inputs and the selection of cost-
effective solutions. For instance, processes may be established to
prioritize finding solutions via long-term planning in the first
instance wherever possible, or to incorporate multiple drivers and
probabilistic benefit cost assessments into the reliability planning
process, so as to leverage the benefits of multi-value planning.
---------------------------------------------------------------------------

    \19\ Regional Planning NOPR, 179 FERC ] 61,028.
---------------------------------------------------------------------------

B. Need for Further Actions To Ensure System Reliability

    12. The Commission developed a robust record in response to the
Commission's technical conference on climate change, extreme weather,
and electric system reliability, and the Commission's technical
conference to discuss resource adequacy developments in the Western
Interconnection.\20\ Today's NOPR will facilitate better planning for
extreme weather events, but the record in those dockets, as well as in
the Commission's inquiry into potential improvements in transmission
system planning,\21\ suggests action is necessary on several fronts to
better facilitate cost-effective solutions. It is important to
highlight three areas for which further inquiry is merited: \22\ (1)
increasing interregional transfer capability; (2) improving
transmission scheduling and coordination in non-RTO regions; and (3)
ensuring that planning and market mechanisms properly reflect resource
availability during extreme weather

events, accounting for the possibility of common mode failures or other
correlated outages.
---------------------------------------------------------------------------

    \20\ See Docket Nos. AD21-13 and AD21-14.
    \21\ See Docket No RM21-17.
    \22\ While this statement highlights key priority areas for
further inquiry, it is not intended to be exclusive. See supra n.
10.
---------------------------------------------------------------------------

1. Increasing Interregional Transfer Capability

    13. Numerous commenters have highlighted that interregional
transfer capability renders the grid more resilient to extreme weather
events.\23\ As a recent report from The Brattle Group summarizes,
``[n]umerous studies have confirmed the significant benefits of
expanding interregional transmission in North America, demonstrating
that building new interregional transmission projects can lower overall
costs, help diversify and integrate renewable resources more cost
effectively, and reduce the risk of high-cost outcomes and power
outages during extreme weather events.'' \24\
---------------------------------------------------------------------------

    \23\ See Post-Conference Comments of American Electric Power,
Docket No. AD21-13, at 8 (filed Sept. 27, 2021) (arguing that
increased interregional transfer capability is ``an important
component of meeting the challenges'' extreme weather poses for the
system); Post-Conference Comments of Midcontinent Independent System
Operator Inc., Docket No. AD21-13, at 23 (filed Sept. 27, 2021)
(finding interregional transfer capacity improves the resilience of
the power system); Comments of Americans for a Clean Energy Grid,
Docket No. AD21-11 (filed Feb. 22, 2022), Attachment 1: Grid
Strategies LLC, Fleetwide Failures: How Interregional Transmission
Tends to Keep the Lights On When There is a Loss of Generation (Nov.
2021), Attachment 2: Grid Strategies LLC, Transmission Makes the
Power System Resilient to Extreme Weather (July 2021), Attachment 3:
Grid Strategies, LLC, The One-Year Anniversary of Winter Storm Uri,
Lessons learned and the Continuing Need for Large-Scale Transmission
(Feb. 13, 2022), Attachment 4: General Electric International, Inc.,
Potential Customer Benefits of Interregional Transmission (Nov. 29,
2021), and Attachment 5: Pfeifenberger et al., A Roadmap to Improved
Interregional Transmission Planning (Nov. 30, 2021); Initial
Comments of PJM Interconnection, L.L.C., Docket No. RM21-17, at 72-
73 (filed Oct. 12, 2021) (``Greater interregional transfer
capability has a significant reliability benefit for both adjoining
regions as demonstrated . . . by the February 2021 Cold Snap and the
2014 Polar Vortex.'') (emphasis omitted).
    \24\ Pfeifenberger et al., A Roadmap to Improved Interregional
Transmission Planning (Nov. 30, 2021) at iii, available at https://www.brattle.com/wp-content/uploads/2021/11/A-Roadmap-to-Improved-Interregional-Transmission-Planning_V4.pdf; see also id. at 2, Table
1, Summary of Select Recent Interregional Transmission Studies.
---------------------------------------------------------------------------

    14. Yet Eversource Energy observes that ``[d]espite numerous
studies suggesting the importance of increased interregional ties, most
planning regions do not currently perform regular studies to assess
whether increased interregional transmission capability could increase
reliability during severe weather events.'' \25\ This gap in planning,
along with many other barriers to constructing interregional transfer
capability,\26\ threatens to dissuade transmission planners and
planning coordinators from pursuing enhanced interregional transfer
capability as a corrective action strategy, even where it is the most
effective solution for customers.
---------------------------------------------------------------------------

    \25\ Post-Conference Comments of Eversource Energy, Docket No.
AD21-13, at 6-7 (filed Sept. 27, 2021).
    \26\ See Pfeifenberger et al. at 4-5 (summarizing barriers to
interregional transmission planning and development).
---------------------------------------------------------------------------

    15. As highlighted in section A above, consistent benchmark cases,
scenarios, and other modeling practices will help to facilitate
transmission planners and planning coordinators' pursuit of shared
solutions, such as enhanced interregional transfer capability. Yet even
with a common framework, coordination between regions is likely to
prove challenging. Setting a minimum level of transfer capability could
provide a unified planning goal for neighboring regions and thereby
ameliorate this planning challenge.\27\ American Electric Power (AEP)
recommends that ``a minimum interregional transfer capability should be
established through a thorough risk assessment on a nationwide, and
region to region basis, using sensitivity analyses on the frequency of
extreme weather events, projections of climate change impacts, and
project retirements, constraints, and load changes over various
timelines.'' \28\ A capability requirement might vary, for instance,
according to a region's generation mix, load, weather, and correlation
with neighboring regions across these various attributes, and would
protect system reliability by ``provid[ing] the ability to access
additional generation in the event local (or even regional) generation
is unable to serve customers or maintain reliability.'' \29\
---------------------------------------------------------------------------

    \27\ See, e.g., Post-Conference Comments of PJM Interconnection,
L.L.C., Docket No. AD21-13, at 19-20 (filed Apr. 15, 2021) (noting
that a ``national standard or recommended planning driver for bi-
directional transfer capability'' would facilitate ``interregional
coordination'').
    \28\ Post-Conference Comments of American Electric Power, Docket
No. AD21-13, at 10 (filed Sept. 27, 2021).
    \29\ Id. at 9-10.
---------------------------------------------------------------------------

    16. A process for setting interregional transfer capability
requirements could address a gap in existing regulation. As AEP argues,
``[b]ecause the current process evaluates transfer capability on a
regional, or balancing authority-specific basis,'' it does not capture
``the efficiencies'' of connections ``between the regions.'' \30\
``[F]ailure to evaluate the grid as a whole makes the grid more
susceptible to . . . the impacts of increasingly extreme weather events
that impact large geographic areas,'' rendering ``the overall
resilience and reliability the transmission grid less robust than it
could be.'' \31\
---------------------------------------------------------------------------

    \30\ Id. at 9.
    \31\ Id.
---------------------------------------------------------------------------

    17. As this discussion suggests, both section 215 and section 206
of the Federal Power Act are implicated by the development of
interregional transfer capability. I urge stakeholders and this
Commission to further explore whether section 215, section 206, or a
combination thereof may serve as the basis for establishing specific
minimum interregional transfer capability requirements or otherwise
establishing least regrets interregional planning targets.

2. Improving Transmission Scheduling and Coordination in Non-RTO
Regions

    18. Enhanced transmission scheduling and coordination between
balancing area authorities--in particular, RTO-to-non-RTO and non-RTO-
to-non-RTO coordination--would improve grid reliability during extreme
weather events, lower costs for customers, and level the regulatory
playing field between RTO and non-RTO regions. Transmission scheduling
and coordination can potentially be improved both via mandating a
transition to flowgate methodology for determining transmission
capacity in areas that continue to use path-based methodologies, and
via facilitation of economic redispatch and narrowing the circumstances
under which transmission curtailment procedures are permissible.
    19. As leading electricity market economists have observed, ``in an
electricity network, power flows along parallel paths dictated by
physical laws rather than the contract path, creating widespread
externalities whose complexity grows with network size.'' \32\ Without
``an appropriate mechanism to allocate transmission capacity''
according to true flow, market participants ``are unlikely to take into
consideration the effects of power flows that diverge from the contract
path.'' \33\ Despite the efficiencies of a flow-based method, however,
the Reliability Standards continue to permit entities to choose either
a path-based or a flow-based method of transmission method,\34\ with
most entities in the Western

Interconnection continuing to use the less efficient path-based
method.\35\
---------------------------------------------------------------------------

    \32\ Chao et al., Flow-based Transmission Rights and Congestion
Management, Electricity Journal at 39 (2000), available at https://oren.ieor.berkeley.edu/pubs/flowbase.pdf.
    \33\ Id.
    \34\ NERC Reliability Standard MOD-29 sets forth requirements
for path-based transmission management, while Reliability Standard
MOD-30 sets forth the requirements for a flow-based method.
    \35\ See Joint Comments of Arizona Public Service Company and
Public Service Company of Colorado, Docket No. AD21-14, at 5-6
(filed Jan. 31, 2022).
---------------------------------------------------------------------------

    20. Arizona Public Service and Public Service Company of Colorado
argue that ``the path based approach results in less efficient
transmission system use and could hamper the contracting and delivery
of capacity resources across the Western Interconnection.'' \36\ By
contrast, ``a flow-based methodology, through its more realistic
assessment of impacts to the entirety of the transmission system, in
general enables greater utilization of the system as a whole.'' \37\ As
the West faces increased frequency and duration of extreme weather
events, achieving maximum reliability value from all existing
infrastructure is imperative.\38\ This raises the question whether the
Reliability Standards should require all applicable entities to
transition to a flow-based methodology.
---------------------------------------------------------------------------

    \36\ Id. at 5.
    \37\ Id. at 6.
    \38\ See Technical Conference Tr., June 24, 2021, Docket No.
AD21-14-000, at 301:14 (Chairman Glick: ``I'm wondering if there are
things we can do in the near term . . . that would help facilitate
and improve [the] resource adequacy situation or at least improve
[the] reliability situation.''); 307:2 (Amanda Ormond, in response:
``I want to just talk about efficiency of the existing transmission
system because we certainly need to get more out of what we have,
and Alice Jackson from [X]cel mentioned the flow-based [methodology]
as you did. I think that's really important that we move to a flow[-
based methodology] because [that would facilitate] know[ing] more
about what's on the system where.'').
---------------------------------------------------------------------------

    21. Beyond ensuring that transmission capacity is measured and
scheduled in a manner that better matches the reality of the system,
the Commission should explore complementary action to improve the
ability of non-RTO system operators to provide transmission service
when the grid is constrained. Transmission Loading Relief (TLR)
procedures and Qualified Path Unscheduled Flow Relief (USF) procedures,
the default methods of managing transmission congestion between
balancing areas outside of RTO/ISO markets, are blunt instruments that
in some cases fail to facilitate power transfers that would aid system
reliability during extreme weather, and in other cases impose higher
overall costs than appropriate redispatch of generation. As MISO
highlights in its post-technical conference comments in Docket No.
AD21-13, TLR fails to ``assure reliable service'' because it ``reli[es]
on curtailment of interchange transactions.'' \39\ TLR and USF
procedures curtail transactions in a pre-set priority order, without
locational marginal pricing or another adequate mechanism to guide them
toward redispatching generation to facilitate optimal transmission
flows. By contrast, economic ``[r]edispatch offers a way, in the vast
majority of circumstances, to ensure that all transactions continue to
be served despite transmission congestion.'' \40\ RTO and ISOs
generally utilize TLRs to mitigate an overload only where they have
``exhausted all other means available, short of load shedding.'' \41\
---------------------------------------------------------------------------

    \39\ Post-Conference Comments of Midcontinent Independent System
Operator, Docket No. AD21-13, at 10 (filed Sept. 27, 2021).
    \40\ Id.
    \41\ See, e.g., PJM Manual 37, Reliability Coordination Sec.
4.1; Southwest Power Pool, Congestion Management & Communication
Processes, 5, 12-13 (2013).
---------------------------------------------------------------------------

    22. While the existing pro-forma Open Access Transmission Tariff
(OATT) currently permits a transmission provider to use redispatch to
maintain reliability during transmission constraints,\42\ David Patton
of Potomac Economics, the independent market monitor for NYISO, MISO,
ISO-NE, and ERCOT, testified at the extreme weather technical
conference that he was ``unaware in non-market areas of any redispatch
that's actually being provided in order to supply transmission
service.'' \43\ The Commission should investigate how it may be able to
facilitate economic redispatch in non-RTOs and reduce usage of TLRs and
USFs in these areas. I am not aware of any systematic examination of
the magnitude of potential benefits to improved coordination practices,
but they are likely significant. During winter storm Uri, sophisticated
RTO transmission scheduling practices facilitated the flow of between
10,000 and 14,000 MW from PJM to support operations in MISO and
beyond.\44\ Yet the use of such practices is not universal. TLRs were
invoked on average over 200 times per year in the Eastern
Interconnection across the past four years.\45\ Public data for USFs,
used across the Western Interconnection where economic redispatch is
less prevalent, is not available.
---------------------------------------------------------------------------

    \42\ See pro forma OATT Sec.  33.2 (providing that network and
native load resources will be redispatched without regard to
ownership on a least cost basis to provide the amount of congestion
relief assigned to all network and native load customers, and that
the costs of such redispatch will be allocated on a load ratio share
basis).
    \43\ See Technical Conference Tr., June 2, 2021, Docket No.
AD21-13-000, at 67:21-23 (filed July 22, 2021).
    \44\ See Technical Conference Tr., Docket No. AD21-13, at 64:5-7
(Renuka Chatterjee) (filed July 22, 2021) (stating that PJM sent
10,000 to 14,000 MW to MISO and areas west of MISO during the
February event).
    \45\ See NERC, TLR Logs, available at https://www.nerc.com/pa/rrm/TLR/Pages/TLR-Logs.aspx (last accessed June 14, 2022).
---------------------------------------------------------------------------

    23. I encourage non-RTO system operators to take action to improve
their transmission scheduling practices, to highlight for the
Commission challenges that they face in doing so, and to identify
potential solutions to those challenges. Absent voluntary improvements
by non-RTO system operators, I believe it would be appropriate for the
Commission to consider requiring changes to the pro forma OATT to
mandate transmission scheduling improvements. As MISO argues, ``greater
grid connectedness that has developed since Order No. 890, emerging
reliability needs not met by the status quo, including the TLR process,
and the inflexibility of the TLR process in responding to extreme
weather . . . have potentially created conditions that may make the
lack of reliability redispatch to bordering utilities potentially
unjust and unreasonable.'' \46\
---------------------------------------------------------------------------

    \46\ Post-Conference Comments of Midcontinent Independent System
Operator, Docket No. AD21-13, at 11 (filed Sept. 27, 2021).
---------------------------------------------------------------------------

    24. While some commenters endorsed the general idea of improving
transmission scheduling practices,\47\ MISO was the only entity to
provide detailed recommendations and factual support for doing so.\48\
MISO provides several suggestions to the Commission, including (1)
encouraging seams agreements that require non-RTOs/ISOs to compensate
RTOs/ISOs for redispatch provided through market flows and for RTOs/
ISOs to compensate non-RTOs/ISOs for reliability redispatch, when the
market flows or the reliability redispatch are the more economical
solution to a congestion problem at their seam, (2) allowing an RTO/ISO
to file a presumptively just and reasonable unexecuted joint operating
agreement or other agreement incorporating such redispatch provisions
in cases where an RTO/ISO cannot reach agreement with a neighboring
non-RTO/ISO transmission provider on joint redispatch,\49\ (3)
clarifying that the reliability redispatch provided under OATT section
33.2 is

available sub-hourly,\50\ and (4) modifying OATT section 33.2 to permit
redispatch not just by network resources of the transmission provider
and its network transmission customers, but also from other generators
including merchants.\51\ It also more broadly recommends ``[m]odifying
the pro forma OATT to require least cost dispatch of a transmission
provider's resources and to require network resources to manage seam
congestion'' such ``that, in addition to requiring reliability
redispatch when feasible to relieve constraints within the transmission
provider's own system, the transmission provider is also required to
provide such service to each of its directly-connected public utility
neighbors (or non-jurisdictional transmission providers that provide
reliability redispatch) prior to implementing TLR procedures.'' \52\
---------------------------------------------------------------------------

    \47\ See, e.g., Post-Conference Comments of Natural Resources
Defense Council, Sierra Club, Sustainable FERC Project, and Union of
Concerned Scientists, Docket No. AD21-13, at 13 (filed Sept. 27,
2017) (arguing that improved coordination of exports and imports
between RTOs/ISOs and non-RTO/ISO regions will enhance system
resilience); Post-Conference Comments of the Michigan Public Service
Commission, Docket No. AD21-13, at 10 (filed Sept. 24, 2021)
(strongly supporting improved coordination and management at market
seams).
    \48\ See Post-Conference Comments of Midcontinent Independent
System Operator, Docket No. AD21-13, at 10 (filed Sept. 27, 2021).
    \49\ Id. at 9, 14-15.
    \50\ Id. at 11-12.
    \51\ Id. at 13.
    \52\ Id. at 11.
---------------------------------------------------------------------------

    25. These recommendations warrant serious consideration. A more
robust record is necessary to examine these ideas and other potential
actions to improve transmission system scheduling, management, and
coordination. I encourage stakeholders to bring forth proposals to the
Commission on this topic, and to provide comments and information
pertinent to the ideas discussed herein. I further recommend that the
Commission take action to gather more information on these issues, such
as by issuing a notice of inquiry, an order directing reports from NERC
and the relevant Balancing Authorities, or a combination thereof, in
order to gather more information on the use of path based management as
well as USFs and TLRs,\53\ the potential benefits of improved
transmission scheduling, management, and coordination practices, and
how such improvements could be achieved. Such proceedings could gather
data on the extent to which additional transmission capacity could be
freed up via a transition to flowgate methodologies, and the extent to
which TLR and USF procedures are unnecessarily curtailing transmission
that could have otherwise been facilitated by economic redispatch. They
could also examine how non-RTO market operators could implement
economic redispatch in the absence of organized markets setting
locational marginal prices.
---------------------------------------------------------------------------

    \53\ NERC publishes data on TLR events on its website, but does
not provide easily accessible information regarding the
circumstances necessitating TLR usage. See https://www.nerc.com/pa/rrm/TLR/Pages/TLR-Logs.aspx (last accessed June 13, 2022). I am not
aware of public data on the use of USFs in the Western
Interconnection.
---------------------------------------------------------------------------

3. Properly Accounting for Resource Availability During Extreme Weather
    26. As many commenters stressed in response to the Commission's
technical conference examining extreme weather, another pressing issue
is the need to ensure that planning procedures, resource adequacy
mechanisms, and reserves markets appropriately reflect the availability
of resources during extreme weather events, properly accounting for
common mode outages or other correlated outages.\54\
---------------------------------------------------------------------------

    \54\ See, e.g., Comments of Buckeye Power, Inc., Docket No.
AD21-13 at 7 (filed Apr. 15, 2021) (``[N]ew planning criteria for
resource adequacy should be developed that expressly address extreme
weather events and other unusual scenarios that can threaten
reliability.''); Comments of Tabors Caramanis Rudkevich, Docket No.
AD21-13, at 10-11, 21-24 (filed Apr. 15, 2021) (stating that
seasonal resource adequacy assessments ``do not . . . adequately
account for either common mode events or extreme events perceived to
have a low probability,'' and advocating for ``the adoption of
advanced resource adequacy methodologies and technologies that are
capable of evaluation of large numbers of stochastically generated
scenarios that incorporate and quantify both common mode events and
the probability of extreme events''); Comments of Dominion Energy
Services, Inc., Docket No. AD21-13, at 5 (filed Apr. 15, 2021)
(``Constraints arising on natural gas pipelines during extreme
weather may also impact the viability of operating reserves relied
upon by the Regional Transmission Organizations,'' potentially
leaving them ``with a false sense of security that [they have] a
sufficient amount of operating reserves'' when that is not the
case.); Comments of LS Power Development, LLC, Docket No. AD21-13,
at 4 (filed Apr. 15, 2021) (``[P]lanning procedures must recognize
and account for common mode failure among various resource classes
with respect to particular weather events and require protections
and redundancies to prevent catastrophic failures like those that
occurred in Texas.'').
---------------------------------------------------------------------------

    27. Resource adequacy methodologies, in particular, are an area
where accurately assessing anticipated availability of resources is
critical so as to ensure that applicable planning and market design
achieves the desired target level of system reliability. Commenters at
the extreme weather technical conference generally agreed that existing
methods are outdated and do not appropriately reflect extreme
weather.\55\ Failure to appropriately account for resource availability
jeopardizes the reliability of grid systems in extreme weather, so
doing the hard work of updating these methodologies is an urgent
concern.
---------------------------------------------------------------------------

    \55\ See, e.g., June 1, 2021 Tr. at 31:15 (Lisa Barton) (``[T]he
current deterministic planning methodology that we have used today [
] works when supply is highly dispatchable[,] when weather is
predictable[, and] when peak demand is reached only a few days a
year,'' and ``fundamentally needs to change'' to address current
conditions); 112-113, 127-128 (Mark Lauby) (highlighting the
outdated nature of 1-in-10 LOLE, and noting that it was developed on
the assumption that generator forced outages are independent, an
unrealistic assumption given the likelihood of common mode events
caused by extreme weather); at 118 (Richard Tabors) (``Our resource
adequacy metrics and planning methods systematically understate the
probability, the depth, and economic health and safety costs of high
impact events.'').
---------------------------------------------------------------------------

    28. NYISO and PJM have made significant strides recently in
establishing processes to ensure that their capacity markets better
account for correlated availability of resources,\56\ but more work is
needed to implement these mechanisms, and to ensure that they are
fairly assessing the contributions of different resource types. While
NYISO's approved proposal explicitly contemplates extending this
methodology to all resource types (albeit while providing very limited
detail on how it will do so),\57\ PJM's approved method is confined to
wind, solar, storage, and hybrid resources.\58\ ISO-NE's external
market monitor has argued that applying ELCC to thermal resources would
better reflect their value.\59\
---------------------------------------------------------------------------

    \56\ See PJM Interconnection, L.L.C., 176 FERC ] 61,056, at P 3
(2021) (approving a proposal by PJM to implement an ELCC methodology
for crediting variable and limited duration resources); New York
Independent System Operator, 179 FERC ] 61,102, at PP 75-82 (2022)
(approving NYISO's proposal to implement a marginal capacity
accreditation design via either ELCC or a similar Marginal
Reliability Improvement technique).
    \57\ 179 FERC ] 61,102 at PP 79, 90.
    \58\ 176 FERC ] 61,056 at P 7.
    \59\ See Potomac Economics, 2020 Assessment of the ISO New
England Electricity Markets, June 2021 at 92 (``EFORd alone does not
accurately describe'' the reliability value of ``intermittent
renewables, energy-limited resources, long lead time or very large
conventional generators, and generators that can experience a common
loss of a limited fuel supply'' because ``these resource types pose
the risk of correlated outage or limited availability of a large
amount of capacity under peak conditions''), and 84 (arguing that
the availability of these resource types is overestimated in GE-
MARS, ISO-NE's resource adequacy model).
---------------------------------------------------------------------------

    29. Further inquiry is necessary to investigate appropriate
methodologies for accounting for correlated outages of resources during
extreme weather, including common mode outages related to unavailable
fuel supply such as gas-fired resources without fuel during winter
events or hydro-electric resources experiencing drought conditions, and
correlated de-rates that may occur in relation to extreme weather such
as difficulty cooling thermal facilities. I urge stakeholders, grid
operators, and my colleagues at the Commission to work expeditiously to
address these questions and facilitate appropriate market reforms.

C. Conclusion

    30. As the Extreme Weather NOPR highlights, climate change poses a
severe reliability threat to the bulk electric system. Addressing that
threat is

a multi-faceted challenge posing complex issues for which there is no
single answer. However, if implemented in a comprehensive and cost-
effective manner, today's NOPR promises to be an important and prudent
step forward in protecting customers against the effects of extreme
weather. By taking complementary actions in the future that build on
this step, the Commission will continue to fulfill its responsibility
of ensuring bulk electric system reliability.
    For these reasons, I respectfully concur.

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

Allison Clements,

Commissioner.
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Transmission System Planning Performance Requirements for Extreme
Weather
Docket No. RM22-10-000
(Issued June 16, 2022)
    PHILLIPS, Commissioner, concurring:
    1. I concur in today's Notice of Proposed Rulemaking \1\ to
emphasize the critical importance of ensuring that the Bulk-Power
System is prepared for extreme weather events in both the near-term and
long-term. While this NOPR has the potential to reduce the threat to
the reliability of the electric system, I note that we must remain
vigilant as much work remains to ensure reliable delivery of power to
consumers during times of stress and to resolve resilience concerns on
the transmission system.
---------------------------------------------------------------------------

    \1\ Transmission System Planning Performance Requirements for
Extreme Weather, 179 FERC ] 61,195 (2022) (NOPR).
---------------------------------------------------------------------------

    2. Climate change and extreme weather are, of course, complex
issues of enormous importance to the United States. In my view, this
NOPR is another step on the path to mitigating the long-term effects of
extreme weather; however, I remain concerned about the grid's near-term
reliability, particularly during the upcoming summer and winter
seasons.\2\ Still, with that in mind, I am voting in favor of issuing
this NOPR because it is needed as an incremental improvement to
Reliability Standard TPL-001-5.1 (Transmission System Planning
Performance Requirements), which I believe currently contains a
reliability gap.\3\
---------------------------------------------------------------------------

    \2\ On August 24, 2021, the Commission approved revised
Reliability Standards to address certain reliability risks posed by
extreme cold weather. Cold Weather Reliability Standards, 176 FERC ]
61,119, at P 1 (2021).
    \3\ To its credit, in the wake of Winter Storm Uri, the North
Electric Reliability Corporation (NERC) issued a level 2 NERC Alert
to industry on cold weather preparations for extreme weather events,
which acknowledged the reliability risks associated with more
frequent extreme weather conditions. NERC, Alert R-2021-08-18-01
Extreme Cold Weather Events (Aug. 18, 2021) (``The recent extreme
cold weather events across large portions of North America have
highlighted the need to assess current operating practices and
identify some recommended improvements, so that system operations
personnel are better prepared to address these challenges. The
events have caused major interruptions to resources, transmission
paths and ultimately, end-use customers.'').
---------------------------------------------------------------------------

    3. The NOPR proposes to direct NERC to modify Reliability Standard
TPL-001-5.1 to require the development of benchmark planning cases
based on past extreme heat and cold weather events.\4\ Currently,
Reliability Standard TPL-001-5.1 does not prescribe specific
benchmarks, and I believe determining and using the appropriate
benchmark will lead to better planning. While extreme weather can be
unpredictable, applying a suitable benchmark study should lead to
understanding resource availability and load shedding requirements
under harsh conditions. Indeed, using benchmarks may also improve
interregional coordination when load shedding and cascading outages
occur.\5\
---------------------------------------------------------------------------

    \4\ NOPR at PP 51-56.
    \5\ See infra at PP 6-8.
---------------------------------------------------------------------------

    4. The NOPR also proposes to direct NERC to modify Reliability
Standard TPL-001-5.1 to require corrective action plans when
performance requirements for extreme heat and cold weather events are
not met.\6\ Currently, the reliability standards require that
responsible entities evaluate possible actions to reduce the likelihood
or mitigate the consequences of such events. These entities, however,
are not obligated to take corrective actions to ensure such failures do
not happen again.\7\ I believe this NOPR rightly identifies this gap
and assures that transmission planners rigorously address uncertainties
surrounding extreme weather events in the planning process.
---------------------------------------------------------------------------

    \6\ NOPR at PP 6, 83.
    \7\ Id. at P 83 (``[P]lanning coordinators and transmission
planners are required to evaluate possible actions to reduce the
likelihood or mitigate the consequences of extreme events but are
not obligated to developed corrective action plans. Specifically, if
such events are found to cause cascading outages, they need only be
evaluated for possible actions designed to reduce their likelihood
or mitigate their consequences and adverse impacts [citation
removed]. Accordingly, because of their potential severity, we
believe that extreme heat and cold weather events should require
evaluation and the development and implementation of corrective
action plans to help protect against system instability,
uncontrolled separation, or cascading failures as a result of a
sudden disturbance or unanticipated failure of system elements.'').
---------------------------------------------------------------------------

    5. Looking forward, and beyond the important charge we have
proposed here, I believe the Commission should next consider further
interregional reliability planning reforms. When we issued a NOPR on
regional transmission planning and cost allocation in April, I said in
my concurrence:
    As we continue to examine those issues, I urge the Commission to
act expeditiously to propose interregional reliability planning
reforms. Looking beyond regional boundaries is important so that cost-
efficient regional and interregional projects can be considered and
studied together. We should consider whether neighboring regions should
adopt common planning assumptions and methods that allow for region-
specific inputs. Additionally, I believe we must consider whether to
adopt a requirement for a minimum amount of interregional transfer
capacity to protect against shortfalls, especially during extreme
weather events.\8\
---------------------------------------------------------------------------

    \8\ Building for the Future through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, 179 FERC ] 61,028 (2022) (Phillips, Comm'r,
concurring, at P 7).
---------------------------------------------------------------------------

    I note we will continue to develop the record in our proceeding on
regional transmission planning and cost allocation, and in response to
today's NOPR. We should examine these and other records closely to
determine the best course of further action on this ripe issue.
    6. The regional nature of extreme weather highlights the
difficulties facing our industry in addressing highly variable risks.
The challenges facing California are very different from the challenges
facing Texas. I believe a minimum transfer capability requirement is
needed, because enhanced transfer capability may be the best way to
take advantage of the diversity of energy sources and the many ways in
which we can support the grid. Order No. 1000 was intended to encourage
more interregional planning and development,\9\ but, simply put,
interregional projects are not being constructed,\10\ and transfer
capacity in

effect has been limited. Many commenters also point out the importance
of adopting a minimum level of interregional transfer capability.\11\
---------------------------------------------------------------------------

    \9\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ]
61,051 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 61,132
(2012), order on reh'g and clarification, Order No. 1000-B, 141 FERC
] 61,044 (2012), aff'd sub nom. D.C. Pub. Serv. Auth. v. FERC, 762
F.3d 41 (D.C. Cir. 2014).
    \10\ See Americans for a Clean Energy Grid, Planning for the
Future: FERC's Opportunity to Spur More Cost-Effective Transmission
Infrastructure, https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf (``For all of the best efforts
of the Commission and regional planning authorities, the current set
of transmission regulations have resulted in inadequate levels of
infrastructure that have burdened the interconnection process with
the task of planning new network facilities--a task that should
instead take place in the planning process. Further, existing
regulations have created a system that disproportionally yields
projects that address only local needs, that address reliability
without more broadly assessing other benefits, or that simply
replace old retiring transmission assets with the same type and
design despite the potential for larger projects to more cost
effectively meet the same needs.'').
    \11\ See, e.g., AEP Post-Conference Comments, Docket No. AD21-
13-000, at 8-12 (filed Sept. 27, 2021) (``The need for regions to
assist each other in extreme weather events has become more frequent
over the past decade, thus highlighting the value, and limitations,
of current interregional transmission capabilities.''); Michigan
Public Service Commission Post-Conference Comments, Docket No. AD21-
13-000, at 12-13 (filed Sept. 24, 2021) (stating that it supports
improving existing interregional coordination methods, such as a
target level of interregional transfer capacity a target level of
regional transfer capacity, to prepare for extreme weather events);
PJM Interconnection, L.LC. Post-Conference Comments, Docket No.
AD21-13-000, at 19-20 (filed Sept. 27, 2021) (stating that a DOE
National Labs study can identify transfer metrics to evaluate an
appropriate level of import/export capability by balancing authority
in terms of percentage of load); Public Interest Organizations Post-
Conference Comments, Docket No. AD21-13-000, at 22-23 (filed Sept.
27, 2021) (discussing different methodologies for achieving a
minimum level of interregional transfer capacity).
---------------------------------------------------------------------------

    7. Indeed, Winter Storm Uri highlighted the need for establishing a
minimum level of interregional transfer capability. Almost half of the
Electric Reliability Council of Texas (ERCOT) was forced out during the
storm, which prompted cascading outages in Texas.\12\ The Midcontinent
Independent System Operator, Inc. (MISO) and the Southwest Power Pool
(SPP) also experienced generation loss during the winter storm, but
were able to request assistance from each other and from PJM
Interconnection, L.L.C. (PJM) through their transmission
interconnections.\13\ As such, SPP maintained service for most of its
load, except for a small portion of its customers over two of its
areas.\14\ Conversely, ERCOT was unable to avail itself of sufficient
mutual assistance during Uri because of its limited transfer
capabilities.\15\ Therefore, I believe it is important that we consider
proposing a minimum level of interregional capacity to aid in times of
severe stress. I urge stakeholders to comment on the steps the
Commission can take to facilitate a minimum level of interregional
transfer capability, and whether there are ways to support existing
interregional coordination methods.
---------------------------------------------------------------------------

    \12\ See Testimony of James Robb, NERC President and Chief
Executive Officer, before the Subcommittee on Oversight and
Investigations Committee on Energy and Commerce, United States House
of Representatives, ``Power Struggle: Examining the 2021 Texas Grid
Failure,'' Mar. 24, 2021, https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Robb_OI_2021.03.24.pdf.
    \13\ FERC-NERC Regional Entity Staff Report, The February 2021
Cold Weather Outages in Texas, and the South-Central United States,
at 14, 66, 127, 141, 167 (Nov. 2021) (2021 Cold Weather Report).
    \14\ 2021 Cold Weather Report at 10-11.
    \15\ 2021 Cold Weather Report at 183 (``ERCOT, unlike MISO and
SPP, . . . did not have the ability to import many thousands of MW
from the Eastern Interconnection, and thus needed to shed the
greatest quantity of firm load to balance electricity demands with
the generating units that were able to remain online.'').
---------------------------------------------------------------------------

    8. I also encourage stakeholders to comment on whether the
Commission should require revisions to RTO/ISO generation and
transmission outage scheduling practices. Planned generation and
transmission outages are critical for facilitating needed equipment
maintenance. Failure to perform such maintenance in a timely fashion
can lead to increased risks of failure of such facilities, including
the potential for unscheduled, forced outages--outages that could
negatively affect the reliability of the grid. Therefore, my preference
is to develop a further record regarding whether RTOs/ISOs should have
wider discretion to coordinate planned outages to make sure all
resources and equipment are available at the time of a reliability
event, which sometimes can be incredibly hard to predict.
    9. By way of example, not all RTOs/ISOs are able to delay or cancel
planned outages for economic reasons, even though the estimated
economic impact of the outage could signal a vulnerability to a
reliability issue if there is another outage in the same area.\16\
Given our growing need to rely on these facilities during the shoulder
months, I believe that planned generation and transmission outages
could increasingly be a driver of reliability concerns, especially
should an extreme weather event occur. Therefore, I urge stakeholders
to comment on the provisions in RTO/ISO tariffs regarding the authority
to recall or cancel planned outages, and whether those practices ensure
that all possible resources can be called upon to assist during extreme
weather events. I am also interested in whether rules requiring
replacement capacity in the event of extended outages would address
these scheduling issues.
---------------------------------------------------------------------------

    \16\ See Eversource Post-Conference Comments, Docket No. AD21-
13-000, at 5 (filed Sept. 27, 2021) (``As noted by the Commission,
ISO-NE already has the ability to deny outages based on economic
impact.''); but see MISO Post-Conference Comments, Docket No. AD21-
13-000, at 19 (filed Sept. 27, 2021) (explaining that when
reliability concerns are present, MISO works with generators to
explore rescheduling outages).
---------------------------------------------------------------------------

    10. Further, I would support a FERC/NERC joint effort to consult
with state and local regulators on these complex issues, especially as
more states are taking increasingly ambitious actions throughout the
country to stem the effects of climate change and extreme weather. I
believe it is beneficial to increase coordination with states and state
regulators because climate change and extreme weather issues raise
difficult challenges that will be novel to all relevant
jurisdictions.\17\ State and federal regulators must endeavor to pursue
reliability solutions that are in accord with one another. In addition,
while state and local action is vital to preventing the worst effects
of extreme weather, federal leadership is also critical. State
regulators may not have visibility into how the Bulk-Power System may
respond to reliability events, so greater coordination with federal
authorities would allow them to answer local stakeholders as to how the
entire system is performing country-wide.\18\ I encourage stakeholders
to comment on whether and to what extent FERC, NERC, and state and
local regulators can better coordinate on extreme weather reliability
matters.
---------------------------------------------------------------------------

    \17\ See, e.g., PJM Pre-Conference Comments, Docket No. AD21-13-
000, at 9 (filed Apr. 15, 2021) (explaining that coordination with
states on climate change and extreme weather events is of utmost
importance in the role of retail regulators and other federal
agencies); Speaker Materials of Devin Hartman, R Street Institute,
at the Technical Conference to Discuss Climate Change, Extreme
Weather and Electric System Reliability, Docket No. AD21-13-000, at
1 (filed June 3, 2021) (discussing many reliability deficiencies,
which include disjointed state-federal coordination and siloed
reliability institutions); see also Motion to Intervene and Comments
of the National Association of Regulatory Utility Commissioners,
Docket No. AD21-13-000, at 2 (filed Apr. 15, 2021) (``The Commission
most certainly should confer with the states . . . where climate
change and extreme weather events may implicate both federal and
state issues.'').
    \18\ See Technical Conference Tr., June 2, 2021, Docket No.
AD21-13-000, at 130-131:1-25 (Letha Tawney) (``I would ask FERC to
think of the state regulators in our role, in our states, as sort of
the face of electricity and natural gas . . . [W]e don't have good
visibility into how the bulk system is going to respond . . . And
without good visibility into how the transmission system is adopting
to these risks, [then we are] in a difficult position with our local
stakeholders.'').
---------------------------------------------------------------------------

    11. Finally, I note that this NOPR is not set in stone and only
asks for comments in response to proposed directives to NERC. There is
much good in this NOPR, and there is much more

work to be done.\19\ I look forward to examining all the comments as we
seek to issue a final rule around these topics.
---------------------------------------------------------------------------

    \19\ For instance, Commissioner Clements is right in pointing
out that we must also take a close look at existing resource
adequacy mechanisms and ancillary service markets. See NOPR
(Clements, comm'r, concurring) at PP 26-27.
---------------------------------------------------------------------------

    For these reasons, I respectfully concur.
-----------------------------------------------------------------------
Willie L. Phillips,

Commissioner.

[FR Doc. 2022-13471 Filed 6-24-22; 8:45 am]
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Denise Gerth/ RTP/ USEPA/ US 01/ 25/ 2006 06: 50 AM To " Flynn, Amy E." < Amy_ E._ Flynn@ omb. eop. gov> cc bcc Subject Re: comments 8 hour ozone reconsideration notice We'll look these over; also received your fax changes. Thanks.

Denise M. Gerth Ozone Policy and Strategies Group U. S. Environmental Protection Agency Research Triangle Park, NC 27711 ( 919) 541 5550  telephone ( 919) 54l 0824  fax " Flynn, Amy E." < Amy_ E._ Flynn@ omb. eop. gov> 01/ 24/ 2006 03: 25 PM To Denise Gerth/ RTP/ USEPA/ US@ EPA cc Subject comments 8 hour ozone reconsideration notice Please find attached comments from DOD on the reconsideration notice for the 8 hour ozone phase I rule. Please let me know if you have any questions.

Thank you,  Amy


[Federal Register Volume 85, Number 134 (Monday, July 13, 2020)]
[Rules and Regulations]
[Pages 41924-41925]
[FR Doc No: 2020-13787]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R01-OAR-2020-0132; FRL-10011-52-Region 1]

Air Plan Approval and Air Quality Designation; Connecticut;
Determination of Clean Data for the 2008 8-Hour Ozone Standard for the
Greater Connecticut Area

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final action.

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SUMMARY: The Environmental Protection Agency (EPA) is finalizing a
clean data determination for the Greater Connecticut Serious 8-hour
ozone nonattainment area, concluding that the area has monitored
attainment of the 2008 8-hour National Ambient Air Quality Standard
(NAAQS) for ozone, based upon certified 2016-2018 ozone data. This
action suspends the requirements for this area to submit an attainment
demonstration, a reasonable further progress plan, contingency
measures, and other planning State Implementation Plan (SIP) revisions
related to attainment of the 2008 8-hour ozone NAAQS on the condition
that the area continues to attain the 2008 8-hour ozone NAAQS. This
action is being taken in accordance with the Clean Air Act.

DATES: This final action is effective on August 12, 2020.

ADDRESSES: EPA has established a docket for this action under Docket
Identification No. EPA-R01-OAR-2020-0132. All documents in the docket
are listed on the https://www.regulations.gov website. Although listed
in the index, some information is not publicly available, i.e., CBI or
other information whose disclosure is restricted by statute. Certain
other material, such as copyrighted material, is not placed on the
internet and will be publicly available only in hard copy form.
Publicly available docket materials are available at https://www.regulations.gov or at the U.S. Environmental Protection Agency, EPA
Region 1 Regional Office, Air and Radiation Division, 5 Post Office
Square--Suite 100, Boston, MA. EPA requests that if at all possible,
you contact the contact listed in the FOR FURTHER INFORMATION CONTACT
section to schedule your inspection. The Regional Office's official
hours of business are Monday through Friday, 8:30 a.m. to 4:30 p.m.,
excluding legal holidays and facility closures due to COVID-19.

FOR FURTHER INFORMATION CONTACT: Elizabeth Townsend, Air Quality
Branch, U.S. Environmental Protection Agency, Region 1, 5 Post Office
Square--Suite 100, (Mail code 05-2), Boston, MA 02109-3912, tel. (617)
918-1614, email<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Throughout this document whenever ``we,''
``us,'' or ``our'' is used, we mean EPA.

Table of Contents

I. Background and Purpose
II. Final Action
III. Statutory and Executive Order Reviews

I. Background and Purpose

    On March 27, 2020 (85 FR 17301), EPA published a notice of proposed
rulemaking (NPRM) for the State of Connecticut. The NPRM proposed to
determine that the Greater Connecticut Serious 8-hour ozone
nonattainment area has attained the 2008 8-hour NAAQS for ozone, based
on 2016-2018 ozone data. Since the NPRM was published, EPA has
finalized and published the design values for 2019, based on 2017-2019
ozone data. These data support the conclusion that the Greater
Connecticut area attains the 2008 8-hour NAAQS for ozone.
    On April 20, 2020 (85 FR 21796), EPA published a correction to the
proposed rule which corrected information, displayed in Table 1, of the
2016 fourth-high 8-hour ozone average concentration values for the
Abington, Cornwall, and East Hartford monitors. Although incorrect
values were displayed in the original version of the proposed rule, the
correct values were utilized in the calculation of the design values
and in the analysis for the clean data determination and therefore did
not change our analysis or conclusions. EPA proposed to determine that
the obligation for Connecticut to make submissions to meet certain CAA
requirements related to attainment of the NAAQS for this area is not
applicable for as long as the area continues to attain the NAAQS. The
rationale for EPA's proposed action is explained in the NPRM and will
not be restated here. No public comments were received on the NPRM.

II. Final Action

    For the reasons stated in the proposed action, EPA is finalizing a
clean data determination for the Greater Connecticut Serious 8-hour
ozone nonattainment area based on the area's current attainment of the
2008 8-hour ozone standard. Pursuant to 40 CFR 51.1118, this action
suspends the requirements for this area to submit State Implementation
Plan (SIP) revisions related to attainment of the 2008 8-hour ozone
NAAQS on the condition that the area continues to attain the 2008 8-
hour ozone NAAQS. In particular, as discussed in the proposed action
(85 FR 17301), the obligation for Connecticut to submit attainment
demonstrations and associated reasonably available control measures,
reasonable further progress plans, contingency measures for failure to
attain or make reasonable progress and other planning SIPs related to
attainment of the 2008 ozone NAAQS shall be suspended until such time
as:

(1) The area is redesignated to attainment for the 2008 8-hour ozone
NAAQS, at which time the requirements no longer apply; or (2) EPA
determines that the area has violated the 2008 8-hour ozone NAAQS, at
which time the area is again required to submit such plans.

III. Statutory and Executive Order Reviews

    Under the Clean Air Act, the Administrator is required to approve a
SIP submission that complies with the provisions of the Act and
applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a).
Thus, in reviewing SIP submissions, EPA's role is to approve state
choices, provided that they meet the criteria of the Clean Air Act.
Accordingly, this action merely approves state law as meeting Federal
requirements and does not impose additional requirements beyond those
imposed by state law. For that reason, this action:
     Is not a significant regulatory action subject to review
by the Office of Management and Budget under Executive Orders 12866 (58
FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
     Is not an Executive Order 13771 regulatory action because
this action is not significant under Executive Order 12866;
     Does not impose an information collection burden under the
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
     Is certified as not having a significant economic impact
on a substantial number of small entities under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.);
     Does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4);
     Does not have federalism implications as specified in
Executive Order 13132 (64 FR 43255, August 10, 1999);
     Is not an economically significant regulatory action based
on health or safety risks subject to Executive Order 13045 (62 FR
19885, April 23, 1997);
     Is not a significant regulatory action subject to
Executive Order 13211 (66 FR 28355, May 22, 2001);
     Is not subject to requirements of Section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272
note) because application of those requirements would be inconsistent
with the Clean Air Act; and
     Does not provide EPA with the discretionary authority to
address, as appropriate, disproportionate human health or environmental
effects, using practicable and legally permissible methods, under
Executive Order 12898 (59 FR 7629, February 16, 1994).
    In addition, the SIP is not approved to apply on any Indian
reservation land or in any other area where EPA or an Indian tribe has
demonstrated that a tribe has jurisdiction. In those areas of Indian
country, the action does not have tribal implications and will not
impose substantial direct costs on tribal governments or preempt tribal
law as specified by Executive Order 13175 (65 FR 67249, November 9,
2000).
    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2).
    Under section 307(b)(1) of the Clean Air Act, petitions for
judicial review of this action must be filed in the United States Court
of Appeals for the appropriate circuit by September 11, 2020. Filing a
petition for reconsideration by the Administrator of this final action
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. (See section 307(b)(2).)

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by
reference, Ozone, Reporting and recordkeeping requirements.

    Dated: June 22, 2020.
Dennis Deziel,
Regional Administrator, EPA Region 1.
[FR Doc. 2020-13787 Filed 7-10-20; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register: November 28, 2007 (Volume 72, Number 228)]
[Notices]
[Page 67294-67295]
[DOCID:fr28no07-43]

=======================================================================
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ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-OAR-2003-0225; FRL-8498-9]

Agency Information Collection Activities; Submission to OMB for
Review and Approval; Comment Request; Populations, Usage and Emissions
of Diesel Nonroad Equipment (Renewal); EPA ICR No. 2156.02, OMB Control
No. 2060-0553

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice.

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SUMMARY: In compliance with the Paperwork Reduction Act (PRA)(44 U.S.C.
3501 et seq.), this document announces that an Information Collection
Request (ICR) has been forwarded to the Office of Management and Budget
(OMB) for review and approval. This is a request to renew an existing
approved collection. The ICR, which is abstracted below, describes the
nature of the information collection and its estimated burden and cost.

DATES: Additional comments may be submitted on or before December 28,
2007.

ADDRESSES: Submit your comments, referencing Docket ID No. EPA-HQ-OAR-
2003-0225, to (1) EPA online using www.regulations.gov (our preferred
method), by e-mail to<EMAIL_ADDRESS>or by mail to: EPA Docket
Center, Environmental Protection Agency, Air and Radiation Docket and
Information Center, Environmental Protection Agency, Mailcode: 2822T,
1200 Pennsylvania Ave., NW., Washington, DC 20460, and (2) OMB by mail
to: Office of Information and Regulatory Affairs, Office of Management
and Budget (OMB), Attention: Desk Officer for EPA, 725 17th Street,
NW., Washington, DC 20503.

FOR FURTHER INFORMATION CONTACT: James Warila, Office of Transportation
and Air Quality, Assessment and Standards Division, (ASD),
Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor,
Michigan 48105; telephone number:<PHONE_NUMBER>; fax number: 734-214-
4821; email address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: EPA has submitted the following ICR to OMB
for review and approval according to the procedures prescribed in 5 CFR
1320.12. On August 9, 2007 (72 FR 44843), EPA sought comments on this
ICR pursuant to 5 CFR 1320.8(d). EPA received one comment during the
comment period, which is addressed in the ICR. Any additional comments
on this ICR should be submitted to EPA and OMB within 30 days of this
notice.
    EPA has established a public docket for this ICR under Docket ID
No. EPA-HQ-OAR-2003-0225, which is available for online viewing at
www.regulations.gov, or in person viewing at the Air and Radiation
Docket in the EPA Docket Center (EPA/DC), EPA West, Room 3334, 1301
Constitution Ave., NW., Washington, DC. The EPA/DC Public Reading Room
is open from 8 a.m. to 4:30 p.m., Monday through Friday, excluding
legal holidays. The telephone number for the Reading Room is 202-566-
1744, and the telephone number for the Air and Radiation Docket is 202-
566-1742.
    Use EPA's electronic docket and comment system at

www.regulations.gov, to submit or view public comments, access the
index listing of the contents of the docket, and to access those
documents in the docket that are available electronically. Once in the
system, select ``docket search,'' then key in the docket ID number
identified above. Please note that EPA's policy is that public
comments, whether submitted electronically or in paper, will be made
available for public viewing at www.regulations.gov as EPA receives
them and without change, unless the comment contains copyrighted
material, confidential business information (CBI), or other information
whose public disclosure is restricted by statute. For further
information about the electronic docket, go to www.regulations.gov.
    Title: Populations, Usage and Emissions of Diesel Nonroad Equipment
(Renewal).
    ICR numbers: EPA ICR No. 2156.02, OMB Control No. 2060-0553.
    ICR Status: This ICR is scheduled to expire on November 30, 2007.
Under OMB regulations, the Agency may continue to conduct or sponsor
the collection of information while this submission is pending at OMB.
An Agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information, unless it displays a currently
valid OMB control number. The OMB control numbers for EPA's regulations
in title 40 of the CFR, after appearing in the Federal Register when
approved, are listed in 40 CFR part 9, are displayed either by
publication in the Federal Register or by other appropriate means, such
as on the related collection instrument or form, if applicable. The
display of OMB control numbers in certain EPA regulations is
consolidated in 40 CFR part 9.
    Abstract: In response to recommendations from the National Research
Council of the National Academy of Sciences, EPA is continuing a
systematic data collection designed to improve the methods and tools
used by the Agency to estimate emissions from nonroad equipment. Data
to be collected include populations, usage rates (activity) and ``in-
use'' or ``real-world'' emission rates.
    The collection is a survey, to be conducted by the Office of
Transportation and Air Quality (OTAQ) in the Office of Air and
Radiation (OAR). Development of rapid in-use instrumentation promises
to substantially reduce the cost of emissions measurement for nonroad
equipment. This study will combine rapid in-use measurement capability
with statistical survey design to improve the representation of nonroad
engine populations. The goal is to continue a pilot survey designed to
develop methods and protocols needed to collect data on populations,
activity and in-use emissions of diesel nonroad equipment. Response to
the survey is voluntary.
    The target population includes nonroad equipment used by commercial
establishments in the construction and manufacturing sectors. The study
area for this collection will include areas in EPA Regions 5 and 7. To
estimate the prevalence of equipment ownership in the target sectors,
establishments will be requested to respond to brief interviews
regarding their equipment ownership and use. The total sample size for
instrumented measurement is 100 equipment pieces, with 50 pieces
targeted for emissions and usage measurement, respectively.
    Emissions and usage will be measured using portable on-board
electronic instrumentation. Emissions instrumentation will measure
carbon dioxide (CO2) and several air pollutants on an
instantaneous basis during normal operation over a period of one to
three days. Air pollutants to be measured include carbon monoxide (CO),
total hydrocarbons (THC), oxides of nitrogen (NOx) and
particulate matter (PM). The usage instrument will measure engine on/
off over a period of approximately one month.
    Data will be collected during normal operation at the respondents'
facilities or work sites. Following quality-assurance and analysis, the
data will be stored in OTAQ's Mobile Source Observation Database. The
information collection will involve 517 respondents per year, requiring
99 hours per year to complete at an annual total cost to those
respondents of $6,716. For the agency, the collection will require
4,455 hours per year at an annual total cost to the agency of $322,415.
    Burden Statement: The annual public reporting and recordkeeping
burden for this collection of information is estimated to average 0.19
hours per response. Burden means the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements which have subsequently changed; train
personnel to be able to respond to a collection of information; search
data sources; complete and review the collection of information; and
transmit or otherwise disclose the information.
    Respondents/Affected Entities: Construction and Manufacturing
Establishments.
    Estimated Number of Respondents: 517.
    Frequency of Response: One-time event.
    Estimated Total Annual Hour Burden: 99.
    Estimated Total Annual Cost: $6,716, includes $0.0 annualized
capital or O&M costs.
    Changes in the Estimates: There is a decrease of 961 hours in the
total estimated burden currently identified in the OMB Inventory of
Approved ICR Burdens. This decrease is due to the fact that EPA
proposes to contact fewer respondents than in the previous approved
ICR, and that burden estimates for individual respondents have been
adjusted downward, based on experience in the previous approval period.

    Dated: November 20, 2007.
Sara Hisel-McCoy,
Director, Collection Strategies Division.
 [FR Doc. E7-23114 Filed 11-27-07; 8:45 am]

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