[Federal Register Volume 87, Number 122 (Monday, June 27, 2022)]
[Proposed Rules]
[Pages 38020-38044]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-13471]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM22-10-000]


Transmission System Planning Performance Requirements for Extreme 
Weather

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission proposes to direct 
that the North American Electric Reliability Corporation, the 
Commission-certified Electric Reliability Organization, submit to the 
Commission modifications to Reliability Standard TPL-001-5.1 
(Transmission System Planning Performance Requirements) within one year 
of the effective date of a final rule in this proceeding to address 
reliability concerns pertaining to transmission system planning for 
extreme heat and cold weather events that impact the reliable 
operations of the Bulk-Power

[[Page 38021]]

System. Specifically, we propose to direct NERC to develop 
modifications to Reliability Standard TPL-001-5.1 to require: 
development of benchmark planning cases based on information such as 
major prior extreme heat and cold weather events or future 
meteorological projections; planning for extreme heat and cold events 
using steady state and transient stability analyses expanded to cover a 
range of extreme weather scenarios including the expected resource 
mix's availability during extreme weather conditions, and including the 
broad area impacts of extreme weather; and corrective action plans that 
include mitigation for any instances where performance requirements for 
extreme heat and cold events are not met.

DATES: Comments are due August 26, 2022.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways. Electronic filing through https://www.ferc.gov, is 
preferred.
     Electronic Filing: Documents must be filed in acceptable 
native applications and print-to-PDF, but not in scanned or picture 
format.
     For those unable to file electronically, comments may be 
filed by U.S. Postal Service mail or by hand (including courier) 
delivery.
    [cir] Mail via U.S. Postal Service only: Addressed to: Federal 
Energy Regulatory Commission, Office of the Secretary, 888 First Street 
NE, Washington, DC 20426.
    [cir] For delivery via any other carrier (including courier): 
Deliver to: Federal Energy Regulatory Commission, Office of the 
Secretary, 12225 Wilkins Avenue, Rockville, MD 20852.

FOR FURTHER INFORMATION CONTACT: 
Mahmood Mirheydar (Technical Information), Office of Electric 
Reliability, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-8034, [email protected]
Milena Yordanova (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE, Washington, 
DC 20426, (202) 502-6194, [email protected]

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                              Paragraph
                                                                 Nos.
 
I. Introduction............................................            1
II. Background.............................................            8
    A. Legal Authority.....................................            8
    B. Climate Change, Extreme Weather, and Electric System           10
     Reliability Technical Conference......................
    C. Overview of Technical Conference Comments...........           13
    D. Cold Weather Reliability Standards..................           18
    E. Reliability Standard TPL-001-4 (Transmission System            20
     Planning Performance Requirements)....................
III. The Need for Reform...................................           24
    A. Recent Events Show Changes in Weather Patterns                 24
     Resulting in More Extreme Heat and Cold Weather Events
    B. NERC Reliability Standards Do Not Require Planning             37
     To Minimize the Increasing Reliability Risks
     Associated With Anticipated Extreme Heat and Cold
     Weather Events........................................
IV. Proposed Directives....................................           47
    A. Develop Benchmark Planning Cases Based on Major                50
     Prior Extreme Heat and Cold Weather Events............
    B. Transmission System Planning for Extreme Heat and              57
     Cold Weather Events...................................
        1. Steady State and Transient Stability Analyses...           58
        2. Transmission Planning Studies of Wide-Area                 64
         Events............................................
        3. Study Concurrent Generator and Transmission                68
         Outages...........................................
        4. Sensitivity Analysis............................           73
        5. Modifications to the Traditional Planning                  75
         Approach..........................................
        6. Coordination Among Planning Coordinators and               80
         Transmission Planners and Sharing of Study Results
    C. Implement a Corrective Action Plan If Performance              83
     Standards Are Not Met.................................
    D. Other Extreme Weather-Related Events and Issues.....           90
V. Information Collection Statement........................           94
VI. Environmental Assessment...............................           96
VII. Regulatory Flexibility Act Certification..............           97
VIII. Comment Procedures...................................          100
IX. Document Availability..................................          103
 

I. Introduction

    1. Pursuant to section 215(d)(5) of the Federal Power Act (FPA),\1\ 
the Commission proposes to direct that the North American Electric 
Reliability Corporation (NERC), the Commission-certified Electric 
Reliability Organization (ERO), submit modifications to Reliability 
Standard TPL-001-5.1 (Transmission System Planning Performance 
Requirements) \2\ that address concerns pertaining to transmission 
system planning for extreme heat or cold weather events that impact the 
reliable operation \3\ of the Bulk-Power System.\4\
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    \1\ 16 U.S.C 824o(d)(5).
    \2\ Transmission Planning Reliability Standard TPL-001-5, Order 
No. 867, 85 FR 8155 (Feb. 13, 2020), 170 FERC ] 61,030, at P 1 
(2020) (approving the proposed Reliability Standard TPL-001-5 and 
associated implementation plan). N. Am. Elec. Reliability Corp., 
Docket No. RD20-8-000 (June 10, 2020) (delegated order) (approving 
Reliability Standard TPL-001-5.1). This NOPR refers to Reliability 
Standard TPL-001-5.1 to reflect that the currently effective version 
4 of the Reliability Standard will be soon replaced by version 5.1 
and any modifications proposed in the NOPR will apply only to TPL-
001-5.1.
    \3\ The FPA defines ``Reliable Operation'' as ``operating the 
elements of the Bulk-Power System within equipment and electric 
system thermal, voltage, and stability limits so that instability, 
uncontrolled separation, or cascading failures of such system will 
not occur as a result of a sudden disturbance, including a 
cybersecurity incident, or unanticipated failure of system 
elements.'' 16 U.S.C. 824o(a)(4).
    \4\ The Bulk-Power System is defined in the FPA as ``facilities 
and control systems necessary for operating an interconnected 
electric energy transmission network (or any portion thereof), and 
electric energy from generating facilities needed to maintain 
transmission system reliability. The term does not include 
facilities used in the local distribution of electric energy.'' Id. 
824o(a)(1).

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[[Page 38022]]

    2. We take this action to address planning challenges associated 
with extreme heat and cold weather events, particularly those that 
occur during periods when the Bulk-Power System must meet unexpectedly 
high demand.\5\ Extreme heat and cold weather events are occurring with 
greater frequency, and are projected to occur with even greater 
frequency in the future.\6\ As such, the impact of concurrent failures 
of Bulk-Power System generators and transmission equipment and the 
potential for cascading outages \7\ that may be caused by extreme heat 
and cold events should be studied and corrective actions should be 
identified and implemented.
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    \5\ Technical Conference June 1-2, 2021, Climate Change, Extreme 
Weather, and Electric System Reliability, Docket No. AD21-13-000 
(June 1-2, 2021), June 1, 2021 Tr. 26: 3-7 (Derek Stenclik, Founding 
Partner, Telos Energy, Inc.), 31:7-8 (Judy Chang, Undersecretary of 
Energy, Massachusetts).
    \6\ Environmental Protection Agency, Climate Change Indicators: 
Weather and Climate (May 12, 2021) (EPA Climate Change Indicators), 
https://www.epa.gov/climate-indicators/weather-climate (showing an 
upward trend in extreme heat and cold weather events).
    \7\ NERC Glossary of Terms Used in Reliability Standards 
(Updated March 29, 2022) (NERC Glossary). NERC defines ``cascading'' 
as, ``The uncontrolled successive loss of System Elements triggered 
by an incident at any location. Cascading results in widespread 
electric service interruption that cannot be restrained from 
sequentially spreading beyond an area predetermined by studies.''
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    3. At the Commission's June 1-2, 2021 technical conference on 
Climate Change, Extreme Weather, and Electric System Reliability, there 
was consensus among panelists that planners cannot simply project 
historical weather patterns forward to effectively forecast the future, 
since climate change has made the use of historical weather 
observations no longer representative of future conditions.\8\ For 
example, extreme heat in summer in regions like the Pacific northwest 
and extreme cold in winter in regions like Texas has increased demand 
for electricity at times when historically demand has been low and such 
events will likely continue to present challenges in the future.\9\ 
Therefore, transmission planners and planning coordinators need to 
reflect these new realities into their planning processes.\10\
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    \8\ June 1, 2021 Tr. 30:2-3 (Chang), 31:12-18 (Lisa Barton, 
Executive Vice President/Chief Operating Officer, American Electric 
Power).
    \9\ June 1, 2021 Tr. 31:1-6 (Chang); June 2, 2021 Tr. 72:8-10 
(Amanda Frazier, Senior Vice President of Regulatory Policy, Vista 
Corp.); 9:1-5 (Wesley Yeomans, Vice President of Operations, New 
York Independent System Operator, Inc. (NYISO)) (noting that in New 
York the majority of the extreme conditions were cold weather 
related but that there can be heat waves in New York City, and more 
heat waves are expected).
    \10\ June 1, 2021 Tr. 35:1-6 (Chang). See also US News, 
Blackouts in US Northwest Due to Heat Wave, Deaths Reported (June 
29, 2021), https://www.usnews.com/news/business/articles/2021-06-29/rolling-blackouts-for-parts-of-us-northwest-amid-heat-wave; Judah 
Cohen et al., Linking Arctic Variability and Change With Extreme 
Winter Weather in the United States, 373 Sci. 1116, 1120 (2021), 
https://www.science.org/doi/10.1126/science.abi9167 (a study 
connecting the 2021 extreme cold weather event in Texas and the 
South-central United States to global warming-induced weather 
anomalies that are likely to continue to produce severe winter storm 
events).
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    4. Since 2011, the country has experienced at least seven major 
extreme heat and cold weather events,\11\ all of which put stress on 
the Bulk-Power System, and resulted in some degree of load shed, and in 
some cases nearly caused system collapse and uncontrolled blackouts, 
which were only avoided via the actions of system operators. Of these, 
the four most severe occurred in 2011, 2013, 2018, and 2021. The 
extreme weather conditions in the February 2011 Southwest Cold Weather 
Event resulted in the acumulative loss of approximately thirty thousand 
megawatts of generation resources, causing the Electric Reliability 
Council of Texas (ERCOT) to shed load to prevent widespread, 
uncontrolled blackouts throughout the entire ERCOT Interconnection. The 
September Midwest and Mid-Atlantic 2013 Heatwave Event lasted over 
three days and at its peak required a 5,791 MW reduction in load. The 
PJM Interconnection, L.L.C. (PJM) analysis during the event indicated a 
need for pre-contingency load shed to avoid post-contingency voltage 
collapse and a potential cascading outage.\12\ During the January 2018 
South Central Cold Weather Event in the Midwest, had the grid operator 
lost the single largest contingency of 1,163 MW, there could have been 
firm load shedding to maintain system stability. In February of 2021, 
the extensive cold in the South Central and Texas regions required a 
combined total of 23,418 MW of firm load shed to maintain Bulk-Power 
System reliability; it was the largest controlled load shedding event 
in U.S. history. During this 2021 Cold Weather Event, had frequency in 
Texas remained under its lowest point on February 15, 2021 for an 
additional five minutes, approximately 17,000 MW of additional 
generation would have tripped, potentially blacking out the entire 
ERCOT Interconnection. ERCOT shed firm load in order to maintain 
frequency to prevent a collapse of the system.\13\
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    \11\ This NOPR references the following seven extreme heat and 
cold weather events experienced since 2011: (1) February 2011 
Southwest Cold Weather Event; (2) September Midwest and Mid-Atlantic 
2013 Heatwave Event; (3) January 2014 Polar Vortex Cold Weather 
Event; (4) January 2018 South Central Cold Weather Event; (5) August 
2020 California Heatwave Event; (6) 2021 Cold Weather Event; (7) 
June 2021 the Pacific Northwest Heatwave Event. The naming of the 
events is based on the title of the associated reliability report 
for each event cited below.
    \12\ PJM, Technical Analysis of Operational Events and Market 
Impacts during the September 2013 Heat Wave, at 13 (Dec. 23, 2013), 
https://www.yumpu.com/en/document/read/40807126/20131223-technical-analysis-of-operational-events-and-market-impacts-during-the-september-2013-heat-wave.
    \13\ FERC, NERC, Regional Entity Staff Report, The February 2021 
Cold Weather Outages in Texas, and the South-Central United States, 
at 133 (Nov. 2021) (2021 Cold Weather Event Report).
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    5. Given the reliability risks associated with extreme heat and 
cold weather events, including the potential for widespread blackouts, 
we believe it would be appropriate for planning of the transmission 
system to account for extreme heat and cold weather events' potential 
impact over wide geographical areas, and to consider the changing 
resource mix and associated planning assumptions. Reliability Standard 
TPL-001-4, the currently effective transmission system planning 
standard, was developed to establish transmission system planning 
performance requirements that ensure that the Bulk-Power System 
operates reliably over a broad spectrum of system conditions and 
following a wide range of probable contingencies. Reliability Standard 
TPL-001-4, and its successor, TPL-001-5.1, includes provisions for 
transmission planners and planning coordinators to study system 
performance under extreme events based on their experience. However, 
the current standards do not specifically require that a performance 
analysis be conducted for extreme heat and cold weather, despite the 
fact that such events have demonstrated a potential harm to reliable 
operations of the Bulk-Power System, thus leaving a gap in system 
planning.
    6. To address this reliability gap, we propose to direct NERC to 
develop modifications to Reliability Standard TPL-001-5.1 to require: 
(1) development of benchmark planning cases based on information such 
as major prior extreme heat and cold weather events or future 
meteorological projections; (2) planning for extreme heat and cold 
events using steady state and transient stability analyses expanded to 
cover a range of extreme weather scenarios including the expected 
resource mix's availability during extreme heat and cold weather 
conditions, and including the broad area impacts of extreme heat and 
cold

[[Page 38023]]

weather; and (3) corrective action plans that include mitigation for 
any instances where performance requirements for extreme heat and cold 
events are not met. In proposing to direct NERC to modify Reliability 
Standard TPL-001-5.1, we are not proposing specific requirements. 
Instead, we identify concerns that we believe should be addressed. NERC 
may propose to develop new or modified Reliability Standards that 
address our concerns in an equally efficient and effective manner. 
However, NERC's proposal should explain how it addresses the 
Commission's concerns.\14\
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    \14\ See e.g., Mandatory Reliability Standards for the Bulk-
Power Sys., Order No. 693, 72 FR 16416 (Apr. 4, 2007), 118 FERC ] 
61,218, at PP 186, 297, order on reh'g, Order No. 693-A, 120 FERC ] 
61,053 (2007) (``where the Final Rule identifies a concern and 
offers a specific approach to address the concern, we will consider 
an equivalent alternative approach provided that the ERO 
demonstrates that the alternative will address the Commission's 
underlying concern or goal as efficiently and effectively as the 
Commission's proposal''); Reliability Standards for Physical Sec. 
Measures, 146 FERC ] 61,166, at P 13 (2014).
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    7. We further propose to direct NERC to submit modifications to 
Reliability Standard TPL-001-5.1 within one year of the effective date 
of a final rule in this proceeding with compliance obligations for all 
proposed new or modified Reliability Standards beginning no later than 
12 months from the date of Commission approval of the modified 
Reliability Standard. Finally, we invite comments on whether to also 
direct NERC to address in Reliability Standard TPL-001-5.1 other 
extreme weather-related events.

II. Background

A. Legal Authority

    8. Section 215 of the FPA requires a Commission-certified ERO to 
develop mandatory and enforceable Reliability Standards, subject to 
Commission review and approval. Reliability Standards may be enforced 
by the ERO, subject to Commission oversight, or by the Commission 
independently.\15\ Pursuant to section 215 of the FPA, the Commission 
established a process to select and certify an ERO,\16\ and 
subsequently certified NERC.\17\
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    \15\ 16 U.S.C. 824o(e).
    \16\ Rules Concerning Certification of the Elec. Reliability 
Org. & Procedures for the Establishment, Approval, & Enf't. of Elec. 
Reliability Standards, Order No. 672, 71 FR 8662 (Feb. 17, 2006), 
114 FERC ] 61,104, order on reh'g, Order No. 672-A, 71 FR 19814 
(Apr. 18, 2006), 114 FERC ] 61,328 (2006).
    \17\ N. Am. Elec. Reliability Corp., 116 FERC ] 61,062, order on 
reh'g and compliance, 117 FERC ] 61,126 (2006), aff'd sub nom. 
Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
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    9. Pursuant to section 215(d)(5) of the FPA, the Commission has the 
authority, upon its own motion or upon complaint, to order the ERO to 
submit to the Commission a proposed Reliability Standard or a 
modification to a Reliability Standard that addresses a specific matter 
if the Commission considers such a new or modified Reliability Standard 
appropriate to carry out section 215 of the FPA.\18\ Further, pursuant 
to Sec.  39.5(g) of the Commission's regulations, the Commission may 
order a deadline by which the ERO must submit a proposed or modified 
Reliability Standard, when ordering the ERO to submit to the Commission 
a proposed Reliability Standard that addresses a specific matter.\19\
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    \18\ 16 U.S.C. 824o(d)(5).
    \19\ 18 CFR 39.5(g) (2021).
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B. Climate Change, Extreme Weather, and Electric System Reliability 
Technical Conference

    10. On March 5, 2021, the Commission announced that staff would 
hold a technical conference to discuss issues surrounding the threat to 
electric system reliability posed by climate change and extreme weather 
events.\20\ The Commission sought to understand, among other things, 
whether further action from the Commission is needed to help achieve an 
electric system that can withstand, respond to, and recover from 
extreme weather events.\21\ On March 15, 2021, the Commission invited 
comments on a range of issues related to Bulk-Power System reliability, 
including how extreme weather events (e.g., hurricanes, extreme heat, 
extreme cold, drought, storms), have impacted the electric system and 
whether these events would require changes to the way generation, 
transmission, substation, or other facilities are designed, built, 
sited, and operated.\22\ The Commission also inquired whether there are 
opportunities to improve the NERC Reliability Standards to address 
vulnerabilities to Bulk-Power System reliability due to climate change 
or extreme weather events in the areas of transmission planning, Bulk-
Power System operations, Bulk-Power System maintenance, and emergency 
operations.\23\
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    \20\ Climate Change, Extreme Weather, and Electric System 
Reliability, Notice of Technical Conference, Docket No. AD21-13-000, 
at 1 (Mar. 5, 2021).
    \21\ Id. at 2.
    \22\ Supplemental Notice of Technical Conference, Docket No. 
AD21-13-000, at 1, 3 (Mar. 15, 2021).
    \23\ Id. at 5.
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    11. On June 1 and 2, 2021, the Commission convened a staff-led 
technical conference on Climate Change, Extreme Weather, and Electric 
System Reliability focused on: (1) ways in which planning practices 
might evolve to achieve outcomes that reflect consumer needs for 
reliable electricity in the face of patterns of climate change and 
extreme weather events that diverge from historical trends; (2) best 
practices throughout the industry for assessing the risks posed by 
climate change and extreme weather and developing cost-effective 
mitigation; (3) ways in which existing operating practices may 
necessitate updated techniques and approaches in light of increasing 
instances of extreme weather and longer-term threats posed by climate 
change; (4) best practices for the recovery period following an extreme 
weather event; and (5) the role that coordination and cooperation 
across jurisdictions could play in planning, operations, and recovery 
practices to address climate change and extreme weather events.\24\
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    \24\ Supplemental Notice of Technical Conference, Docket No. 
AD21-13-000, at 1, 3 (May 27, 2021) (attaching agenda).
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    12. Following the conference, the Commission invited comments on 
specific topics discussed at the conference, such as the possibility 
of: incorporating probabilistic methods into local transmission 
planning and/or regional transmission planning; coordinating transfers 
across the seams between Regional Transmission Organizations; the 
possibility of modifying transmission planning requirements established 
under Reliability Standard TPL-001 to better assess and mitigate the 
risk of extreme weather events and associated common mode failures; 
additional changes to the NERC Reliability Standards to address the 
risk of extreme weather events; and among other topics, whether target 
levels of interregional transfer capacity could help facilitate more 
effective development of interregional transmission projects to help 
ensure reliability and resilience during extreme weather events.\25\
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    \25\ Notice Inviting Post-Technical Conference Comments, Docket 
No. AD21-13-000, at 3, 5 (Aug. 11, 2021).
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C. Overview of Technical Conference Comments

    13. Commenters submitted more than 50 sets of pre-conference and 20 
post-conference comments on a wide range of issues, including the types 
of extreme weather events experienced,\26\ and the range of mitigating 
measures that could be taken to address the specific risks of climate 
change in various regions of the country. Commenters expressed

[[Page 38024]]

concerns that the impacts of climate change are anticipated to affect 
the electric system in multiple, compounding, and synergistic ways.\27\ 
Generally, industry experts agreed that extreme weather events are 
likely to become more severe and frequent in the future,\28\ and 
acknowledged the challenges associated with planning for extreme 
events, including shifting scheduled maintenance, canceling or 
recalling transmission and generation assets from scheduled maintenance 
to meet demand under unexpected circumstances.\29\
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    \26\ See, e.g., California Independent System Operator 
Corporation (CAISO) Pre-Conference Comments at 3.
    \27\ Environmental Defense Fund and Columbia Law School's Sabin 
Center for Climate Change Law Pre-Conference Comments at 4.
    \28\ CAISO Pre-Conference Comments at 1-3; California Public 
Utilities Commission Pre-Conference Comments at 4; Oregon Public 
Utilities Commission Pre-Conference Comments at 2-3; NYISO Pre-
Conference Comments at 4.
    \29\ June 2, 2021, Tr. at 21-23 (Wesley Yeomans, Vice President 
of Operations, NYISO).
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    14. Some commenters discussed potential changes to the NERC 
Reliability Standards to address planning and operational preparedness 
for energy adequacy risks,\30\ contingencies related to extreme weather 
events, and wide-area transmission planning and development 
challenges,\31\ among others. In addition, participants advocated for 
planning that reflects the new climate-change driven conditions, as the 
expected impacts of climate change ``need to be baked into the rest of 
your planning and development activities.'' \32\
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    \30\ ISO-New England Inc. Pre-Conference Comments at 10.
    \31\ Midcontinent Independent System Operator (MISO) Pre-
Conference Comments at 4-5, 14-17.
    \32\ June 1, 2021 Tr. 136:18-21 (Neil Millar, Vice President, 
Transmission Planning & Infrastructure Development, CAISO).
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    15. Pacific Gas and Electric Company states that Reliability 
Standard TPL-001-4 already requires transmission planners to evaluate 
extreme events, but could benefit from providing further clarity on the 
events to consider, as well as the extent to which investments can be 
made to the grid to mitigate the identified issues for the given event 
evaluated.\33\
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    \33\ Pacific Gas and Electric Company Pre-Conference Comments at 
19-20.
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    16. Post-conference comments also addressed more directly the 
potential reliability gaps in the existing set of Reliability 
Standards, including Reliability Standard TPL-001-4. For example, MISO 
argues that while current Commission-approved Reliability Standards 
provide for the assessment of the impacts of extreme events that may 
include climate-driven weather events, they do not include requirements 
to mitigate consequences from such events.\34\ Similarly, PJM states 
that Reliability Standard TPL-001-4 should be modified to specifically 
account for extreme weather events by mandating regional extreme 
weather design standards for transmission and generation operating 
criteria.\35\ CAISO also states that Reliability Standard TPL-001 may 
not serve as the best means to assess the threat and risk of extreme 
weather events.\36\
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    \34\ MISO Post-Conference Comments at 20.
    \35\ PJM Post-Conference Comments at 21.
    \36\ CAISO Post-Conference Comments at 10.
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    17. NERC agrees that with proper planning, including consideration 
not only of historic temperature averages but also consideration of 
conditions during extreme weather events and the linkage between 
critical infrastructures, the risks associated with extreme weather and 
the changing resource mix can be mitigated.\37\ NERC agrees that 
enhancements to the Reliability Standards could be beneficial. Some 
examples of potential enhancements include requiring reliability 
coordinators, balancing authorities, or planning coordinators to 
determine the temperature to which plants in their respective areas 
must weatherize; requiring reliability coordinators or balancing 
authorities to develop seasonal emergency energy management plans, to 
address conditions such as wildfires, extreme hot and cold 
temperatures, and severe storms (i.e., hurricanes); requiring 
reliability coordinators to develop a rolling three week emergency 
energy management plan; and requiring balancing authorities to prepare 
a seasonal energy management plan based on regional extreme weather 
scenarios identified in NERC's seasonal assessments.\38\
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    \37\ NERC Pre-Conference Comments at 6.
    \38\ Id. at 15-16; NERC Post-Conference Comments at 5-7 
(explaining that additional modifications to the Reliability 
Standards may be appropriate as the resource mix is transformed to 
one that is more sensitive to severe weather conditions, as some 
types of severe weather events or conditions could result in the 
loss of a substantial amount of resources due to fuel concerns).
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D. Cold Weather Reliability Standards

    18. NERC and the Commission have begun to address the effects of 
extreme cold weather on generating units, specifically focusing on 
improved performance of generating units during cold weather 
conditions. On August 24, 2021, the Commission approved revised 
Reliability Standards to address some of the reliability risks posed by 
extreme cold weather.\39\ Effective April 2023, those Reliability 
Standards will, inter alia, require generators to implement plans for 
cold weather preparedness and require the balancing authority, 
transmission operator, and reliability coordinator to plan and operate 
the grid reliably during cold weather conditions by requiring the 
exchange of certain information related to the generator's capability 
to operate under such conditions.\40\
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    \39\ N. Am. Elec. Reliability Corp., 176 FERC ] 61,119 (2021). 
The Commission approved proposed Reliability Standards EOP-011-2 
(Emergency Preparedness and Operations); IRO-010-4 (Reliability 
Coordinator Data Specification and Collection); and TOP-003-5 
(Operational Reliability Data) (collectively, the Cold Weather 
Reliability Standards).
    \40\ Id. P 3.
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    19. The proposed improvements to transmission planning discussed in 
this NOPR and the requirements in the Cold Weather Reliability 
Standards both work together to mitigate the reliability impact of 
extreme weather events, such as the 2021 Cold Weather Event in Texas 
and South-Central United States. To ensure reliability, transmission 
planning should be considered in the context of generators' performance 
and availability during extreme heat and cold events.

E. Reliability Standard TPL-001-4 (Transmission System Planning 
Performance Requirements)

    20. Transmission system planning refers to the evaluation of future 
transmission system performance and creation of corrective action plans 
that includes mitigation for extreme heat and cold events to remedy 
identified deficiencies.\41\ The planning horizon associated with 
transmission system planning covers near term (one to five years), 
long-term (six to 10 years), and beyond.\42\
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    \41\ NERC Glossary defines ``Planning Assessment'' as 
``documented evaluation of future Transmission System performance 
and Corrective Action Plans to remedy identified deficiencies.''
    \42\ Id.
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    21. Reliability Standard TPL-001-4, applicable to planning 
coordinators and transmission planners, establishes minimum 
transmission system planning performance requirements within the 
identified planning horizon to plan a Bulk-Power System that will 
operate reliably over a broad spectrum of system conditions and follow 
a wide range of probable contingencies.\43\ Under Reliability Standard 
TPL-001-4, and Reliability Standard TPL-001-5.1, Requirement R2, each 
transmission planner and planning coordinator must prepare an annual 
planning assessment of its portion of the Bulk-Power System based on 
current or qualified past studies, document its assumptions, and 
document the summarized results of the

[[Page 38025]]

steady state analyses, short circuit analyses, and stability 
analyses.\44\ This planning assessment is required for both near-term 
and long-term transmission planning horizons.\45\
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    \43\ Reliability Standard TPL-001-4, Purpose.
    \44\ Reliability Standard TPL-001-4/5.1, Requirement 2. Further, 
steady-state analyses are a snapshot in time where load and system 
conditions (e.g., generators, lines, facilities) are modeled as 
constant (not as changing over time). The analysis will either solve 
or diverge (not solved). See IEEE, Transactions on Power Systems, 
Vol. 19, No. 2, (May 2004) (power system stability is the ability of 
an electric power system, for a given initial operating condition, 
to regain a state of operating equilibrium after being subjected to 
a physical disturbance, with most system variables bounded so that 
practically the entire system remains intact); see also, Kundur, 
Prabha, Power System Stability and Control, McGraw Hill, at 26 
(1994).
    \45\ See Reliability Standard TPL-001-4, Requirement 2.1 (Near-
Term Transmission Planning Horizon) and Requirement R.2.2 (Long-Term 
Transmission Planning Horizon).
---------------------------------------------------------------------------

    22. Requirements R3 and R4 of Reliability Standard TPL-001-4 
require in part that planning coordinators and transmission planners 
conduct steady state and stability analyses of pre-specified extreme 
events and evaluate possible actions designed to reduce the likelihood 
or mitigate the consequences and adverse impacts of the event(s), if 
the analysis concludes that the pre-selected extreme events cause 
cascading outages.
    23. Table 1 of Reliability Standard TPL-001-4 includes a list of 
examples of planning events for which specific studies may be required, 
generally, based on the entity's own evaluation that such an event 
could occur within its operating area. Section 3.a of Table-1, Steady 
State & Stability Performance Extreme Events, states that steady state 
analysis should be conducted for wide-area events affecting the 
transmission system based on system configuration and how it can be 
affected by events such as wildfires and severe weather (e.g., 
hurricanes and tornadoes). In addition, section 3.b serves as a catch-
all provision, stating that steady state analysis should be performed 
for ``other events based upon operating experience that may result in 
wide-area disturbances.''

III. The Need for Reform

A. Recent Events Show Changes in Weather Patterns Resulting in More 
Extreme Heat and Cold Weather Events

    24. Recent extreme weather-related events that spread across large 
portions of the country over the past decade demonstrate the challenges 
to transmission planning from extreme heat and cold weather patterns. 
Since 2011, the country has experienced at least seven major extreme 
heat and cold weather events; of these, four neared system collapse 
(2011, 2013, 2018, and 2021 extreme cold weather events) if the 
operators had not acted to shed load. The remaining three events (2014, 
2020, 2021 extreme heat weather events) resulted in generation loss and 
varying degrees of load shedding.
    25. These extreme heat and cold events demonstrate a risk to 
reliable operation of the Bulk-Power System. Below we discuss in detail 
how recent extreme cold and heat events have demonstrated such risks, 
including resource availability, limitations of the transmission system 
locally and over a wide area, and limitations of interregional transfer 
capabilities.
    26. From February 1 to February 4, 2011, the southwest region of 
the United States experienced unusually cold and windy weather, 
referred to as the February 2011 Southwest Cold Weather Event. Low 
temperatures during the period were in the teens for five consecutive 
mornings and there were many sustained hours of below freezing 
temperatures throughout Texas and New Mexico. Low temperatures in 
Albuquerque, New Mexico ranged from 7 degrees Fahrenheit to minus seven 
degrees Fahrenheit over the period, compared to a normal range of 51 to 
26 degrees Fahrenheit. Temperatures in Dallas, Texas ranged from 19 
degrees to 14 degrees Fahrenheit, compared to a normal range of 60 to 
mid-to-upper 30s degrees Fahrenheit. Many cities in the region did not 
see temperatures above freezing until February 4, 2011. In addition, 
sustained high winds of over 20 mph produced severe wind chill factors. 
The extreme weather conditions resulted in the loss of a significant 
number of generators which occurred almost simultaneously, causing 
ERCOT to shed load to prevent widespread, uncontrolled blackouts 
throughout the entire ERCOT Interconnection.\46\ As a result, 
approximately 4.4 million electric customers were affected over the 
course of the event.\47\
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    \46\ FERC and NERC Staff Report, Outages and Curtailments During 
the Southwest Cold Weather Event of February 1-5, 2011, at 7 (Aug. 
2011), https://www.ferc.gov/sites/default/files/2020-05/ReportontheSouthwestColdWeatherEventfromFebruary2011Report.pdf. Load 
shedding may be used to reduce an overload condition (such as when 
thermal limits on a transmission line are exceeded), to recover from 
an under-frequency condition, or to return voltage to a normal 
level.
    \47\ Id. at 1.
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    27. Two years later, the Midwest and mid-Atlantic experienced 
unseasonably hot weather from September 9 through September 11, 2013, 
which led to emergency conditions in the PJM service area. During this 
period, temperatures ranged from the upper 80s into the 90s Fahrenheit, 
which in some areas like Cleveland translated into conditions of over 
20 degrees above normal.\48\ As a result, demand for electricity 
reached an all-time high for September within PJM's footprint. 
Transmission owners tend to schedule maintenance outages during the 
fall and spring, increasing the risk of system stress during periods of 
weather-related high energy demand, such as occurred in September 2013. 
PJM implemented controlled outages in a few constrained areas to 
prevent uncontrolled blackouts over larger areas that could have 
affected many more customers.\49\ In preparation for another day of 
unseasonably high use of electricity, on September 11, PJM called for 
voluntary demand response \50\ across much of its service area, 
resulting in a 6,048 MW reduction in electricity demand, the largest 
amount of demand response PJM had ever received. During the entire 
event PJM shed 157 MW of load affecting approximately 45,000 
customers.\51\
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    \48\ PJM, Technical Analysis of Operational Events and Market 
Impacts during the September 2013 Heat Wave, at 7, Figure 1, RTO 
Temperatures (Dec. 23, 2013) (PJM Heat Wave Analysis), https://www.yumpu.com/en/document/read/40807126/20131223-technical-analysis-of-operational-events-and-market-impacts-during-the-september-2013-heat-wave.
    \49\ Id. at 4.
    \50\ Under demand response programs, retail customers volunteer 
and are paid to reduce their electricity use when requested.
    \51\ PJM Heat Wave Analysis at 5.
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    28. Another extreme event occurred the following year, in early 
January 2014, when the Midwest, south central, and east coast regions 
of the country experienced an extreme cold weather event known as the 
polar vortex, referred to as the January 2014 Polar Vortex Cold Weather 
Event, where extreme cold resulted in temperatures 20 to 30 degrees 
Fahrenheit below normal.\52\ Some areas faced days that were 35 degrees 
Fahrenheit or more below their normal temperatures. These extreme 
temperatures resulted in record high electrical demand on January 6 and 
again on January 7, 2014. During the January 2014 Polar Vortex Cold 
Weather Event, the cold weather increased demand for natural gas, which 
caused a significant amount of gas-fired generation to become 
unavailable due to unavailability of the non-firm gas purchases they 
relied on. The cold weather and issues from fuel combined for over 
35,000 MW of generator outages during the height of the polar vortex

[[Page 38026]]

weather conditions.\53\ By employing communication tools, interruptible 
load, demand-side management tools, and voltage reduction, balancing 
authorities and load serving entities were mostly able to maintain 
their operating reserve margins and serve firm load and only one 
balancing authority was required to shed 300 MW of firm load. Many 
outages, including a number of those in the southeastern United States, 
were the result of temperatures that fell below a plant's design 
basis.\54\
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    \52\ NERC, Polar Vortex Review (Sept. 2014) (Polar Vortex 
Review), https://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014_Final.pdf.
    \53\ Id. at 4.
    \54\ Id. at iii.
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    29. Further, in mid-January 2018, a large area of the south-central 
region of the United States saw unusually cold weather, with 
temperatures dropping from about five degrees Fahrenheit to as much as 
27 degrees Fahrenheit below the normal daily minimums. Texas, 
Louisiana, Arkansas, Oklahoma, Mississippi, Missouri, and other 
neighboring states were all affected by the extreme cold weather, which 
lasted from January 12 to January 19, 2018, known as the January 2018 
South Central Cold Weather Event.\55\ The reliability coordinators in 
MISO did not anticipate the numerous mitigation measures they would 
need to take to maintain Bulk-Power System reliability at the peak of 
the event (January 17, 2018), including transmission loading relief, 
transmission reconfiguration, and the need to be prepared to shed firm 
load in the event of an additional contingency in MISO South of 1,163 
MW.\56\ Although the system remained stable on January 17, 2018, this 
event represented a near miss of cascading outages.
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    \55\ FERC and NERC Staff Report, The South Central United States 
Cold Weather Bulk Electric System Event of January 17, 2018, at 6-8 
(July 2019) (2018 Cold Weather Event Report), https://www.nerc.com/pa/rrm/ea/Documents/South_Central_Cold_Weather_Event_FERC-NERC-Report_20190718.pdf.
    \56\ Id. at 12.
---------------------------------------------------------------------------

    30. Two years later, the western United States suffered another 
intense and prolonged heatwave affecting many areas across the Western 
Interconnection during a five-day period from August 14 through August 
19, 2020 (August 2020 California Heatwave Event). With temperatures 
between 15- and 30-degrees Fahrenheit above normal, many areas in the 
western parts of the country broke daily heat records. Some areas in 
the southwest posted record temperatures: Phoenix, Arizona reached a 
record 115 degrees Fahrenheit. Even cities located further north had 
similar temperature spikes, with Portland, Oregon, registering 102 
degrees Fahrenheit. Because of these high temperatures, electricity 
demand in the Western Interconnection reached a record high on August 
18, 2020.\57\ On August 14 and 15, CAISO shed firm load to maintain the 
operating reserves needed to maintain the reliability and security of 
the Bulk-Power System. Several other entities reported being one 
contingency away from needing to shed load as well.\58\
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    \57\ Western Electricity Coordinating Council, August 2020 
Heatwave Event Analysis Report, at 1-2 (Mar. 19, 2021) (2020 Heat 
Event Report), https://www.wecc.org/Reliability/August%202020%20Heatwave%20Event%20Report.pdf.
    \58\ Id. at 1.
---------------------------------------------------------------------------

    31. More recently, in February 2021, Texas and the South-Central 
United States experienced the 2021 Cold Weather Event, the fourth cold-
weather-related event in the last ten years to jeopardize Bulk-Power 
System reliability. Temperatures began to drop below freezing in Texas 
and the Southwest Power Pool, Inc. (SPP) region on February 8, 2021, 
but temperatures dropped even lower during the week of February 14, 
reaching their nadir on February 15 and 16, 2021. Daily low 
temperatures for February 15th were as much as 40 to 50 degrees lower 
than average daily minimum temperatures for that day. In addition to 
the arctic air, the cold front brought periods of freezing 
precipitation and snow to large parts of Texas and the South Central 
region, starting February 10, and extending into the week of February 
14, 2021.\59\
---------------------------------------------------------------------------

    \59\ 2021 Cold Weather Event Report at 9, 12-13.
---------------------------------------------------------------------------

    32. This was the most devastating cold-weather-related event in the 
last 10 years to impact Bulk-Power System reliability, with a combined 
23,418 MW of manual firm load shed, the largest controlled firm load 
shed event in U.S. history.\60\ The unplanned generation outages that 
escalated during the event, 65,622 MW, were more than four times as 
large as the previous largest event, in 2011 (14,702 MW).\61\ ERCOT 
faced the greatest challenge due to the magnitude of unplanned 
generating unit outages in its area, coupled with its limited ability 
to import power to help offset generation shortfalls. Notably, the 
entire ERCOT Interconnection has a maximum total import limitation of 
only 1,220 MW, which limited ERCOT's ability to import electricity to 
meet demand.\62\ In Texas alone, this event resulted in more than 4.5 
million people losing power, cost the Texas economy between $80 to $130 
billion, and caused at least 210 deaths.\63\ Had frequency in Texas 
remained under its lowest point for an additional five minutes during 
the peak of the event, approximately 17,000 MW of additional generation 
would have tripped, potentially blacking out the entire ERCOT 
Interconnection. In contrast to ERCOT, some regions, such as MISO and 
SPP, had the ability to import power from the east, where weather 
conditions were less severe, to make up for a large portion of their 
generation shortfalls during the event. For example, PJM was exporting 
an unprecedented amount of electricity into MISO and SPP, reaching over 
15,700 MW of interregional transfers on February 15, 2021.\64\
---------------------------------------------------------------------------

    \60\ Id. at 9.
    \61\ Id.
    \62\ Id. at 127 n.197.
    \63\ Id. at 10.
    \64\ PJM Post-Conference Comments at 17-18; 2021 Cold Weather 
Event Report at 229 n. 355. Interregional transfer capability allows 
an entity in one region with available energy to assist one or more 
entities in another region that is experiencing an energy shortfall 
due to the extreme weather event.
---------------------------------------------------------------------------

    33. Finally, in June 2021 the Pacific Northwest experienced another 
record-breaking heat wave, referred to as June 2021 the Pacific 
Northwest Heatwave. During the event, Seattle set an all-time record 
high temperature of 104 degrees Fahrenheit on June 27, 2021, while 
Portland had two back-to-back all-time records, on June 26 and 27, 
2021, where temperatures reached 108- and 112-degrees Fahrenheit, 
respectively.\65\ While such events are still rare in today's climate, 
researchers believe such events are likely to become more common in the 
future.\66\
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    \65\ Climate Signals, Northwest Pacific Heat Wave June 2021 
(Oct. 2021), https://www.climatesignals.org/events/northwest-pacific-heat-wave-june-2021#/more.
    \66\ Sjoukje Y. Philip, Sarah F. Kew et al., Rapid attribution 
analysis of the extraordinary heatwave on the Pacific Coast of the 
US and Canada (June 2021), at 199, https://www.worldweatherattribution.org/wp-content/uploads/NW-US-extreme-heat-2021-scientific-report-WWA.pdf.
---------------------------------------------------------------------------

    34. While these wide-area extreme events may not occur every year, 
their frequency and magnitude are expected to increase. NOAA's data and 
analyses show an increasing trend in extreme heat and cold events,\67\ 
and the U.S. Environmental Protection Agency climate change indicators 
also show upward trends in heatwave frequency, duration, and 
intensity.\68\ NOAA states that climate change is also driving more 
compound events, which are multiple extreme events occurring 
simultaneously or successively, such as concurrent heat waves and 
droughts,

[[Page 38027]]

and more extreme heat conditions in cities.\69\
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    \67\ NOAA website, Climate Data Online (NOAA website, Climate 
Data Online), https://www.ncdc.noaa.gov/cdo-web/.
    \68\ EPA Climate Change Indicators.
    \69\ NOAA website, Climate Data Online.
---------------------------------------------------------------------------

    35. With respect to extreme cold, NOAA explains that accelerated 
arctic warming is likely contributing to the increasing frequency of 
Arctic polar vortex-stretching events that deliver extreme cold to the 
United States and Canada, including the winter 2021 Texas cold 
wave.\70\ NOAA climate data indicates that the occurrence of 
significant cold weather events is trending higher nationwide.\71\
---------------------------------------------------------------------------

    \70\ NOAA, Climate Program Office, Research Links Extreme Cold 
Weather in the United States to Arctic Warming, https://cpo.noaa.gov/Interagency-Programs/NIHHIS/ArtMID/6409/ArticleID/2369/Research-Links-Extreme-Cold-Weather-in-the-United-States-to-Arctic-Warming?msclkid=f9ad03bcc7c911ecba22ebf3e1ead5d9.
    \71\ NOAA website, Climate Data Online.
---------------------------------------------------------------------------

    36. As discussed, the recent extreme heat and cold events have had 
a significant impact on the reliability of the Bulk-Power System. 
However, the potential impact of widespread extreme heat and cold 
events on the reliability of the Bulk-Power System can be modeled and 
studied in advance as part of near-term and long-term transmission 
system planning. Transmission planners could use the studies to develop 
transmission system operational strategies or corrective action plans 
with mitigation that could be deployed prior to and in preparation for 
extreme heat and cold events. Examples of such corrective action plans 
include planning for additional contingency reserves or implementing 
new energy efficiency programs to decrease load,\72\ planning for 
additional interregional transfer capability, transmission switching/
reconfiguration, or adjusting transmission and generation maintenance 
outages based on longer-lead forecasts. Therefore, given the urgency of 
addressing the negative impact of extreme weather on the reliability of 
the Bulk-Power System, the proposed directives to NERC in this NOPR aim 
to improve system planning specifically for extreme heat and cold 
weather events.
---------------------------------------------------------------------------

    \72\ Contingency reserves would only contribute to a corrective 
action plan to the extent that they are expected to perform during 
the applicable modeled extreme weather event(s) and thereby 
contribute to meeting the applicable performance criteria. 
Accordingly, if for instance, extreme cold is anticipated to cause 
fuel unavailability for the applicable area, a corrective action 
plan would need to account for such limitations.
---------------------------------------------------------------------------

B. NERC Reliability Standards Do Not Require Planning To Minimize the 
Increasing Reliability Risks Associated With Anticipated Extreme Heat 
and Cold Weather Events

    37. The currently effective Reliability Standard TPL-001-4 and the 
to-be-effective TPL-001-5.1, Requirements R3 and R4 require steady 
state and stability analyses to be performed for extreme events 
``listed in Table 1 that are expected to produce more severe system 
impacts.'' Table 1, Steady State & Stability Performance Extreme 
Events, under the Steady State analysis, sections 3.a.iii and 3.a.iv 
lists wildfires and severe weather (e.g., hurricanes and tornadoes) as 
potential events that could be studied. However, neither Requirements 
R3 or R4, nor the associated Table 1 specifically require steady state 
analyses for extreme heat and cold conditions to be completed as part 
of the transmission planner's or planning coordinator's planning 
assessment. Finally, Table 1, provisions 2.f (stability) and 3.b 
(steady state), require the responsible entities to study events based 
on operating experience that may result in a wide-area disturbance, but 
they do not specify the study of extreme heat or cold conditions.
    38. System planning measures alone will not eliminate the 
reliability risk associated with extreme heat and cold events. However, 
system planning will limit the impact of such events and reduce the 
risk to the reliability of the Bulk-Power System, which prior events 
demonstrate is significant.
    39. The country experienced wide-spread cold weather events in 
2011, 2014, 2018, and 2021. With the exception of the January 2018 
South Central Cold Weather Event, planned and unplanned generating unit 
outages caused energy emergencies and triggered the need for firm load 
shed. As evidenced by the last cold weather event in 2021, where 
generation loss and loss of load were the most extreme, it becomes 
increasingly more important to consider changes in transmission 
planning. Although during the January 2018 South Central Cold Weather 
Event the system remained stable, the 2018 Cold Weather Event Report 
addressing this specific event recommended that MISO and other 
reliability coordinators perform voltage stability analyses when under 
similarly constrained conditions, benchmark planning and operations 
models against actual events that strained the system, perform periodic 
impact studies to identify which elements in the adjacent reliability 
coordinators' systems have the most impact on their own systems, and 
perform drills with entities involved in load shedding to prepare to 
execute load-shedding for maintaining reserves while at the same time 
alleviating severe transmission conditions.\73\
---------------------------------------------------------------------------

    \73\ 2018 Cold Weather Event Report at 12-13.
---------------------------------------------------------------------------

    40. Having the necessary data and performing modeling in advance of 
extreme cold temperatures could allow transmission planners and 
operators to assess the potential impact of an event to identify 
corrective actions that could be taken well in advance of the event. 
Such action could include ensuring generators have winterized their 
equipment, scheduling fewer planned outages of generating units and 
transmission lines, and endeavoring to maintain transmission ties 
intact to: (1) permit maximum transfers to an area experiencing a 
deficiency in generation; (2) minimize the possibility of cascading 
outages; and (3) assist in restoring operation to normal.\74\ While 
these corrective action plans may not fully mitigate the potential 
impact of these events, they could minimize the impact and reduce 
system restoration time.
---------------------------------------------------------------------------

    \74\ ERCOT, Nodal Operating Guide, at 137 (Jan. 1, 2022), 
https://www.ercot.com/files/docs/2021/12/21/Nodal%20Operating%20Guide.pdf.
---------------------------------------------------------------------------

    41. Past experience can inform how steady state and stability 
analyses should model transmission and generator outages, including 
availability of wind, natural gas, and other resources sensitive to 
extreme cold conditions. For example, the February 2021 cold weather-
related outages in Texas and the south-central United States caused 
4,125 outages/derates of generating units (i.e., approximately 456 GW 
during event in total event area). Of the total generation losses, 59% 
were gas-fired generating units due to fuel issues \75\ and a pipeline 
equipment failure, and 27% were wind generation due to blade icing.\76\
---------------------------------------------------------------------------

    \75\ Fuel issues included 87% natural gas fuel supply issues 
(decreased natural gas production, terms and conditions of natural 
gas commodity and transportation contracts, low pipeline pressure 
and other issues) and 13% other fuel issues.
    \76\ 2021 Cold Weather Event Report at 163.
---------------------------------------------------------------------------

    42. While heat events have different planning challenges, they also 
present a serious risk to the Bulk-Power System and often require 
operators to shed load to maintain system stability. The recent extreme 
heat events resulted in a variety of reliability issues such as 
controlled rolling blackouts and transmission congestion. During the 
August 2020 California Heatwave Event, wind production was low during 
the evenings, and solar generation was declining during the peak demand 
hours, leading to reserve shortages.

[[Page 38028]]

Similar to Texas, California relies on wind and solar generation to 
meet normal peak day demand, but wind and solar generation were largely 
unavailable. Steady state and stability analyses of study cases modeled 
to reflect past extreme conditions as well as modeling of availability 
of generation resources during extreme heat conditions in the planning 
process could have better prepared the transmission operators for such 
conditions.
    43. Past extreme heat and cold events discussed above demonstrate 
the importance of assessing resource and reserve requirements under 
extreme heat and cold weather conditions. Developing and using extreme 
heat and cold weather scenarios in planning analyses will help to 
identify the potential risks that extreme events may pose to the Bulk-
Power System. Based on the risks identified, appropriate mitigations or 
corrective action plans such as requiring additional reserves and 
transfer capability can be developed and deployed to address the risks 
and specify what should be planned for the longer term to ensure the 
availability of electricity in real time.
    44. NERC recognizes that extreme events present a reliability risk 
and there are opportunities to improve the transmission planning 
processes. Following the 2021 extreme cold weather event, NERC issued a 
level 2 NERC Alert to industry on cold weather preparations for extreme 
weather events with five recommendations to assist reliability 
coordinators, balancing authorities, transmission operators, and 
generator owners in preparing for the winter season. NERC's level 2 
Alerts recommend but do not mandate registered entities to take 
specific actions.\77\ The Alert recommended seasonal operating plans 
for the upcoming winter season, which would include plans to utilize 
additional transmission capacity, consideration of the import 
capability of the system and resource availability constraints on 
external systems, and load forecasting practices that consider extreme 
events, among other recommendations.\78\ The NERC Alert did not include 
any recommendations concerning long-term transmission planning.
---------------------------------------------------------------------------

    \77\ NERC, About Alerts, https://www.nerc.com/pa/rrm/bpsa/Pages/About-Alerts.aspx.
    \78\ NERC, Alert R-2021-08-18-01 Extreme Cold Weather Events 
(Aug. 18, 2021), https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/NERC%20Alert%20R-2021-08-18-01%20Extreme%20Cold%20Weather%20Events.pdf.
---------------------------------------------------------------------------

    45. In addition, in 2021 NERC formed the Energy Reliability 
Assessment Task Force (ERATF) to assess risks associated with unassured 
energy supplies, including the inconsistent output from variable 
renewable energy resources, fuel location, and volatility in forecasted 
load, which can result in insufficient amounts of energy on the system 
to serve electrical demand.\79\ The ERATF uses resource adequacy models 
to address energy availability concerns related to the operations 
planning horizon (i.e., one day to one year) and near-term planning 
horizon (i.e., one to five years).\80\ In December of 2021, the ERATF 
prepared a draft Standard Authorization Request (SAR) and based on the 
comments to the SAR, two SARs were created: a planning SAR and an 
operations/operations planning SAR, aiming to create or modify NERC 
Reliability Standards across the operations/operational planning time 
horizon and the planning time horizon. To discuss this latest update 
with industry members, NERC held an informational Webinar on May 19, 
2022, and the two SARs were scheduled for committee consideration on 
June 8, 2022.\81\
---------------------------------------------------------------------------

    \79\ NERC, Energy Reliability Assessment Task Force website, 
(ERAFT website), https://www.nerc.com/comm/RSTC/Pages/
ERATF.aspx#:~:text=%E2%80%8B%E2%80%8B%E2%80%8B%E2%80%8B%E2%80%8B,insu
fficient%20amounts%20of%20energy%20on.
    \80\ NERC Post-Technical Conference Comments at 7.
    \81\ NERC, Informational Webinar: Industry Webinar Energy 
Reliability Assessment Task Force Update on the Revised SARs (May 
19, 2022), https://www.nerc.com/pa/RAPA/Lists/RAPA/DispForm.aspx?ID=480; NERC, Reliability and Security Technical 
Committee Meeting Agenda, SAR Draft.
---------------------------------------------------------------------------

    46. While these ongoing efforts by NERC and industry members are 
intended to improve system reliability, they do not directly address 
the gap in transmission planning related to extreme heat and cold 
weather. NERC acknowledges that heat and cold events have effects on 
the grid but at this time has not determined that modifications to TPL-
001-5.1 are needed to address extreme weather events.\82\
---------------------------------------------------------------------------

    \82\ NERC, 2021 ERO Reliability Risk Priorities Report, Risk 
Profile 2, at 26 (July 2021), https://www.nerc.com/comm/RISC/Documents/RISC%20ERO%20Priorities%20Report_Final_RISC_Approved_July_8_2021_Board_Submitted_Copy.pdf; see also NERC Post-Conference Comments at 5 
(referencing Reliability Standard TPL-001-4, NERC states that 
``[w]ith respect to extreme weather more generally, NERC staff will 
continue to examine the Reliability Standards to determine if other 
modifications are needed.'').
---------------------------------------------------------------------------

IV. Proposed Directives

    47. We preliminarily find that a reliability gap exists in 
Reliability Standard TPL-001-5.1 with respect to a lack of a long-term 
planning requirement for extreme heat and cold weather events. 
Accordingly, pursuant to section 215(d)(5) of the FPA, we propose to 
direct that NERC develop modifications to Reliability Standard TPL-001-
5.1 to require: (1) development of benchmark planning cases based on 
information such as major prior extreme heat and cold weather events or 
future meteorological projections; \83\ (2) planning for extreme heat 
and cold events using steady state and transient stability analyses 
expanded to consider a range of extreme heat and cold weather scenarios 
(i.e., sensitivities to be applied to the benchmark base case(s)), 
including the expected resource mix's availability during extreme heat 
and cold weather conditions, and including the broad area impacts of 
extreme heat and cold weather; and (3) corrective action plans that 
include mitigation for any instances where performance requirements for 
extreme heat and cold events are not met. We further elaborate on the 
substance of these proposed directives below. In proposing to direct 
NERC to develop modifications to Reliability Standard TPL-001-5.1, we 
are not proposing specific requirements; we are identifying concerns 
that we believe should be addressed. NERC may propose to develop new or 
modified Reliability Standards that address these concerns in an 
equally efficient and effective manner as the requirements proposed in 
this paragraph; however, NERC must explain how its proposal addresses 
the Commission's concerns.\84\
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    \83\ For instance, a benchmark event could be constructed based 
on data from a major prior extreme heat or cold event, with 
adjustments if necessary to account for the fact that future 
meteorological projections may estimate that similar events in the 
future are likely to be more extreme.
    \84\ Order No. 693, 118 FERC ] 61,218 at P 186; Reliability 
Standards for Physical Sec. Measures, 146 FERC ] 61,166 at P 13.
---------------------------------------------------------------------------

    48. We further propose to direct NERC to submit modifications to 
Reliability Standard TPL-001-5.1 within one year of the effective date 
of a final rule in this proceeding with compliance obligations for all 
proposed new or modified Reliability Standards beginning no later than 
12 months from the date of Commission approval of the modified 
Reliability Standard. Finally, we invite comments on whether to also 
direct NERC to address in Reliability Standard TPL-001-5.1 other 
extreme weather-related events.
    49. Below we provide additional context for these three proposed 
directives and describe reliability concerns and potential options for

[[Page 38029]]

consideration that we believe would address these concerns.

A. Develop Benchmark Planning Cases Based on Major Prior Extreme Heat 
and Cold Weather Events

    50. As part of its revisions to Reliability Standard TPL-001-5.1, 
we are proposing to direct that NERC develop requirements that address 
the types of extreme heat and cold scenarios the responsible entities 
are required to study. Reliability Standard TPL-001-5.1 does not 
require any specific approach to studying extreme heat and cold events 
and we are concerned that, without specific requirements describing the 
types of heat and cold scenarios that entities must study, the standard 
may not provide a significant improvement upon the status quo.
    51. To accomplish this, the modified Reliability Standard developed 
by NERC should include benchmark events that responsible entities must 
study, as well as guidelines regarding which range of sensitivities 
must be applied to these benchmark event scenarios. Such benchmark 
events should be based on prior events (e.g., February 2011 Southwest 
Cold Weather Event, January 2014 Polar Vortex Cold Weather Event) and/
or constructed based on meteorological projections, as described above. 
In addition to providing valuable case study information to be applied 
to possible comparable future events, these events will also serve as a 
basis for effectively using assets and resources. Once developed, the 
results of the benchmark events studies could be applied to determine 
the limitations of the transmission system locally and over a wide-
area, and to understand resource availability and potential firm load 
shedding requirements under stressed conditions.
    52. While extreme weather risks may vary from region to region and 
change over time, 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. In determining 
an appropriate benchmark event, NERC should consider approaches to 
provide a uniform framework while still recognizing regional 
differences. For example, NERC could define benchmark events around a 
projected frequency (e.g., 1-in-50-year event) or probability 
distribution (95th percentile event),
    53. We propose to provide NERC with flexibility in defining one or 
more appropriate benchmark events. For example, one approach could be 
for NERC to develop the common benchmark event or events through the 
standards development process and include the relevant parameters of 
the benchmark event or events in the modified reliability standard. 
Another approach could be to include in the modified standard the 
primary features of the benchmark event or events (e.g., the expected 
occurrence such as one-in-50 years) while designating another set of 
entities, such as the Regional Entities, reliability coordinators, or 
even NERC itself, as responsible for periodically updating key aspects 
of the benchmark events based on the most up-to-date data. Such a 
method for developing benchmark events and scenarios could establish a 
common design basis across the industry while still recognizing 
regional differences in climate and weather patterns. We seek comment 
on whether, and to what extent, it may be appropriate to allow 
designated entities to periodically update key aspects of the benchmark 
events.
    54. As discussed further below, establishing one or more benchmark 
events should form the basis for sensitivity analysis, which provide 
better visibility into the actual system conditions during extreme heat 
and cold. For example, sensitivity analysis could include analysis of 
simultaneously varying generation dispatch (e.g., wind, solar, natural 
gas, and other fuel generation availability), system transfers, and 
load, which have been observed during prior extreme heat and cold 
events.
    55. In addition to establishing requirements that address the 
extreme heat and cold scenarios that responsible entities are required 
to study, NERC could also establish measures of system performance 
(stability, voltage, thermal limits, etc.) to determine whether the 
responsible entities must implement a corrective action plan. 
Performance requirements are a corollary to study requirements--without 
clear performance requirements, the obligations on responsible entities 
to mitigate issues with system performance may be unclear. Moreover, 
performance requirements are an integral part of the existing 
Reliability Standard TPL-001-5.1.\85\ Accordingly, NERC should 
incorporate performance requirements for extreme heat and cold 
conditions when modifying TPL-001-5.1.
---------------------------------------------------------------------------

    \85\ See Reliability Standard TPL-001-5.1 (Transmission System 
Planning Performance Requirements), Requirements R1 through R8.
---------------------------------------------------------------------------

    56. In establishing any proposed performance requirements, NERC 
should seek to prevent system instability, uncontrolled separation, and 
cascading outages. While load shedding could still occur during extreme 
heat and cold events to prevent instability, uncontrolled separation, 
and cascading, it should be minimized as much as possible. Developing 
benchmark events and associated corrective actions to be deployed prior 
to and during the event, would result in better system performance in 
real time.

B. Transmission System Planning for Extreme Heat and Cold Weather 
Events

    57. As discussed above, we propose to direct that NERC develop 
modifications to Reliability Standard TPL-001-5.1 to require planning 
for extreme heat and cold events using steady state and transient 
stability analyses expanded to consider a range of extreme heat and 
cold weather scenarios including the expected resource mix's 
availability during extreme heat and cold weather conditions, and 
including the broad area impacts of extreme heat and cold weather. In 
this section, we discuss six topics which NERC would be required to 
address in a modified Reliability Standard pursuant to the proposed 
directive: (1) steady state and transient stability analysis; (2) 
transmission planning studies of wide area issues; (3) concurrent 
generator and transmission outages; (4) sensitivity analysis; (5) 
consideration of modifications to the traditional planning approach; 
and (6) coordination among planning coordinators and transmission 
planners and sharing of results. We note that a range of methods/
approaches could satisfy the Commission's directive with regard to 
issues (3) through (6). NERC would retain flexibility with regard to 
how to address these topics, so long as it incorporates them into its 
proposed solution. To better inform our directive to NERC in the final 
rule, we invite comments on these matters.
1. Steady State and Transient Stability Analyses
    58. To maintain and improve the reliability of the Bulk-Power 
System, it is important to conduct both steady state and stability 
analyses for extreme heat and cold events as part of transmission 
planning studies. As discussed above, steady state and stability 
analyses of study cases modeled to reflect past and forecasted extreme 
heat and cold conditions would better prepare transmission operators 
for such conditions. Further, this approach is consistent with 
Reliability Standard TPL-001-5.1, which requires both steady state and 
stability analyses for extreme events identified in Table 1 of the 
Standard. Performing these studies in the long-term planning horizon 
time frame (i.e., five to 10 years) will provide an adequate lead time 
for entities to

[[Page 38030]]

develop and implement corrective action plans to reduce the likelihood 
or mitigate the consequences and adverse impacts of such events.
    59. A steady-state analysis or assessment is based on a snapshot in 
time where bulk-electric system facilities such as generators, 
transmission lines, transformers, etc. are modeled as fixed and load is 
modeled as a constant. The steady state analysis assesses the ability 
of the system to deliver electricity to load within the ratings and 
constraints of generators and transmission lines. It also includes a 
contingency analysis to predict electrical system conditions when 
elements are removed from the base case.\86\
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    \86\ NERC, Compliance Implementation Guidance Real-time 
Assessment Quality of Analysis, at 3 (May 2019), https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TOP-010-1(i)%2520R3%2520and%2520IRO-018-1(i)%2520R2%2520-
%2520RTA%2520Quality%2520of%2520Analysis%2520(OC).pdf.
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    60. Transient stability or dynamic studies add to the steady state 
analyses simulate the time-varying characteristics of the system during 
a disturbance that occurs during an extreme heat or cold weather event. 
They are time-domain analyses that assess angular stability, voltage 
stability, and frequency excursions.\87\ Transient angular stability is 
the ability of interconnected synchronous machines of a power system to 
remain in synchronism after being subjected to a disturbance (i.e., 
fault, sudden loss of load, and generation tripping).\88\ Transient 
voltage stability refers to the ability of a power system to maintain 
steady voltages at all buses in the system after being subjected to a 
disturbance.\89\
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    \87\ Indian Institute of Technology Patna, Power System Dynamics 
and Control, at 1, (Power System Dynamics), https://www.iitp.ac.in/
~siva/2022/ee549/Introduction_Power_System_Stability.pdf.
    \88\ Id. at 3.
    \89\ Id. at 15.
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    61. While we recognize dynamic studies can be more resource 
intensive to perform, we believe that the consideration of both types 
of studies is important to understand the potential impacts of extreme 
heat and cold weather events. We believe the consideration of dynamic 
studies is particularly important given the changing resource mix and 
the need to understand the dynamic behavior of both traditional 
generators as well as variable energy resources (VER) (mainly wind and 
photovoltaic solar).
    62. To that end, we seek comments on whether planning coordinators 
and transmission planners should include contingencies based on their 
planning area and perform both steady state and transient stability 
(dynamic) analyses using extreme heat and cold cases. We are inviting 
comments on the following topics regarding planning for extreme heat 
and cold weather conditions: (1) the set of contingencies planning 
coordinators and transmission planners must consider; (2) required 
analyses to ensure system stability, frequency excursion and angular 
deviations caused as a result of near simultaneous outages or common 
mode failures of VERs; and (3) the role of demand response under such 
scenarios.
    63. Finally, we emphasize the continued importance of ensuring that 
entities responsible for performing assessments under TPL-001-5.1 are 
able to obtain the necessary data. Currently, the data for steady-
state, dynamic, and short circuit modeling can be obtained pursuant to 
Reliability Standard MOD-32-1, Requirement 1 (Data for Power System 
Modeling and Analysis), which is referenced in Reliability Standard 
TPL-001-5.1. Specifically, Reliability Standard MOD-32-1 allows 
planning coordinators and transmission planners to request data from 
the generator owners and transmission owners, which are obligated to 
provide the specified data.\90\ Consistent with the existing standards, 
we believe it is important for NERC to ensure that registered entities 
responsible for performing studies of extreme weather are able to 
access the data necessary to complete such studies. Accordingly, we 
seek comment on whether the existing Reliability Standards are 
sufficient to ensure that responsible entities performing studies of 
extreme heat and cold weather conditions have the necessary data, or 
whether the Commission should direct additional changes pursuant to FPA 
215(d)(5) to address that issue.
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    \90\ Reliability Standard MOD-032-1, Requirements R1 and R2.
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2. Transmission Planning Studies of Wide-Area Events
    64. As discussed above, our proposed directive would include 
modifications to TPL-001-5.1 to require transmission planning studies 
that consider the broad area impacts of extreme heat and cold weather. 
The effects of extreme weather events on the reliable operation of the 
Bulk-Power System can be widespread, potentially causing simultaneous 
loss of generation and increased transmission constraints within and 
across regions. The studies required by TPL-001-5.1, however, have 
traditionally focused on local planning and typically do not address 
the issues caused by wide-area extreme heat and cold weather events on 
a regional or interconnection scale.\91\
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    \91\ June 1, 2021 Tr. 153: 2-9. (Frederick Heinle, Assistant 
People's Counsel, Office of the People's Counsel for the District of 
Columbia).
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    65. Reliability Standard TPL-001-5.1 does not contemplate the 
consideration of impacts from wide-area events \92\ that may impact 
multiple planning coordinators simultaneously; in contrast, TPL-001-5.1 
only requires identifying and evaluating selected wide-area events 
resulting from conditions such as loss of a large gas pipeline into a 
region or multiple regions that have significant gas-fired generation, 
and does not specify studying potential issues resulting from extreme 
heat and cold.\93\
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    \92\ Reliability Standard TPL-001-5.1, Table 1, Steady State & 
Stability Performance Extreme Events, uses the term ``wide area 
events'' to refer to such things as loss of two generating stations 
resulting from conditions including severe weather or wildfires, 
distinguishing such events from ``local area events'' affecting the 
transmission system, which may involve the isolated loss of a 
transmission tower, substation, or generating station.
    \93\ Reliability Standard TPL-001-5.1, Table 1, Steady State & 
Stability Performance Extreme Events, Section 3(a)(i).
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    66. Failure to study the wide-area impact of extreme heat or 
extreme cold weather conditions when an entity conducts transmission 
planning, could result in reliability issues that simultaneously affect 
multiple regions to remain undetected in the long-term planning 
horizon. This, in turn, could lead to otherwise avoidable situations 
where the system is one contingency away from voltage collapse and 
uncontrolled blackouts.
    67. Based on prior events, we preliminarily find that it is 
appropriate that the study criteria for extreme heat and cold events 
include a consideration of wide-area conditions affecting neighboring 
regions and their impact on one planning area's ability to rely on the 
resources of another region during the weather event. To identify 
opportunities for improved wide-area planning studies and coordination, 
we seek comment on: (1) whether wide-area planning studies should be 
defined geographically or electrically; (2) which entities should 
oversee and coordinate the wide-area planning models and studies (e.g., 
reliability coordinators, regional planning groups); (3) which entities 
should have responsibility to address the results of the studies, and 
how they should communicate those results among transmission planners; 
and (4) how to develop corrective action plans that mitigate issues 
that require corrective action by, and coordination among, multiple 
transmission owners.

[[Page 38031]]

3. Study Concurrent Generator and Transmission Outages
    68. Concurrent outages occur nearly simultaneously in different 
planning areas due to the same extreme weather events, such as the 
unplanned generator outages associated with the major extreme heat and 
cold events discussed above. Generation resources that are sensitive to 
severe weather conditions may cease operation during extreme heat and 
cold events, thus contributing to wide-area concurrent outages. In 
addition, the performance of power transformers, transmission lines, 
and other equipment degrades under extreme heat and may have to come 
out of service. Extreme heat could lead to significant derating, 
reduced lifetime, and even possible failures of power transformers, 
while extreme cold could lead to at least temporary facility 
transmission outages.\94\
---------------------------------------------------------------------------

    \94\ MIT News, Preventing the Next Blackout (Dec. 5, 2017), 
https://news.mit.edu/2017/mit-study-climate-change-effects-large-transformers-1205; see also IEEE Standard C57.91-2011, Table 2; IEEE 
Standard C57.91-2011, Table 3; 2021 Cold Weather Event Report at 95.
---------------------------------------------------------------------------

    69. Therefore, modeling the loss of these generators and 
transmission equipment during extreme heat and cold weather events 
would allow planners to determine the effects of potential concurrent 
transmission and generator outages and study the feasibility (i.e., 
availability and deliverability) of external generation resources that 
could possibly be imported to serve load during such events, thereby 
minimizing the potential impact of extreme heat and cold events on 
customers.\95\ Modeling concurrent generator and transmission outages 
would also allow planners to better identify appropriate solutions to 
be incorporated into corrective action plans.
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    \95\ The Cold Weather Reliability Standards referenced supra 
take effect in April 2023, and are expected to improve generating 
unit performance and help alleviate some of the unsustainable levels 
of generation outages seen during extreme events. Improved 
transmission planning alone cannot overcome the challenges 
associated with generator outages during extreme events. Therefore, 
both the Cold Weather Reliability Standards and this proposal to 
improve transmission planning are necessary for the Bulk Power 
System to perform reliably in the face of future extreme weather 
events.
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    70. Extreme cold effects on generators vary by generator type, 
cooling systems, and fuel sources.\96\ Transmission planners commonly 
assume that the failures of individual generators are independent. This 
understanding, however, is inconsistent with documented historical 
events, that show multiple coincident outages due to the same cause. 
For instance, the 2021 extreme cold event demonstrated the limitations 
of such an assumption. Between February 8 and February 20, 2021, 
approximately 44% of generator outages were caused by freezing issues, 
31% by fuel issues related to extreme cold weather, and another 21% 
were caused by mechanical/electrical failures related to cold 
weather.\97\ Meanwhile, wind turbine generators were the second largest 
share of individual generating units after gas-fired generators that 
suffered freezing issues in the southern part of SPP and Texas, as 
temperatures dropped well below zero degrees Fahrenheit.\98\ 
Transmission facilities were also affected in the short-term, as 
transmission operators managed to return them into service.\99\ 
Likewise, the 2018 Cold Weather Event Report revealed that there is a 
high correlation between generator outages and cold temperatures, 
indicating that as temperatures decrease, unplanned generator outages 
and derates increase.\100\
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    \96\ Polar Vortex Review at 12.
    \97\ 2021 Cold Weather Event Report at 15-16.
    \98\ Id. at 75.
    \99\ Id. at 95.
    \100\ 2018 Cold Weather Event Report at 80.
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    71. Similarly, extreme heat impacts on generators vary by generator 
type, and the common implication is a reduction in the overall 
generation capacity throughout the wide area affected by the heat 
event.\101\ Generally, extreme heat poses more of a threat to the 
functioning of a solar panel than extreme cold. As temperatures 
increase above 77 degrees Fahrenheit, which is a standard test 
condition, solar panels generate less voltage and become less 
efficient,\102\ producing less power for a given amount of solar energy 
depending on the solar panel temperature coefficient.\103\ For example, 
during the 2020 heat event in California, wind and solar generation 
were largely unavailable.\104\ While extreme cold temperatures on clear 
days would not negatively impact energy output. Also, solar panels are 
built to be waterproof to protect the electronic components against 
heavy rain and to withstand hailstorms. However, snow,\105\ ice 
accumulation, or cloud cover that commonly accompany extreme cold 
weather could prevent the panels from receiving as much sunlight, which 
would limit their power production and efficiency.
---------------------------------------------------------------------------

    \101\ Department of Energy, U.S. Energy Sector Vulnerabilities 
to Climate Change and Extreme Weather, Department of Energy, at 19-
22 (July 11, 2013), https://www.energy.gov/sites/default/files/2013/07/f2/20130716-Energy%20Sector%20Vulnerabilities%20Report.pdf 
(listing the impacts of increased ambient air temperature on the 
various types of generators).
    \102\ IEEEXplore, International Conference on Current Trends in 
Computer, Electrical, Electronics and Communication (ICCTCEEC-2017), 
Effect of Temperature on Performance of Solar Panels--Analysis, 
https://ieeexplore.ieee.org/stamp/stamp.jsp?tp=&arnumber=8455109.
    \103\ Temperature coefficient describes the percentage of power 
output that is lost by a specific solar panel as the temperature 
rises above 77 degrees Fahrenheit.
    \104\ 2020 Heat Event Report at 11.
    \105\ A recent study by Sandia National Labs identified snow 
events as causing the largest performance reductions at solar 
facilities. See Nicole D. Jackson & Thushara Gunda, Evaluation of 
Extreme Weather Impacts on Utility-Scale Photovoltaic Plant 
Performance in the United States, 302, Applied Energy, 1:7 (2021), 
https://www.researchgate.net/publication/353944206_Evaluation_of_extreme_weather_impacts_on_utility-scale_photovoltaic_plant_performance_in_the_United_States.
---------------------------------------------------------------------------

    72. Requiring transmission planners and planning coordinators to 
study concurrent generator and transmission failures under extreme heat 
and cold events is one way to address the reliability gap. Accounting 
for concurrent outages in planning studies would provide a more 
realistic assessment of system conditions (i.e., updated conditions 
based on historic benchmarked performance) during potential extreme 
heat and cold events and will help better assess the probability of 
potential occurrences of cascading outages, uncontrolled separation, or 
instability. Transmission planners and planning coordinators could also 
model the derating and possible loss of wind and solar generators, as 
well as natural gas generators sensitive to extreme heat and cold 
conditions. To identify the scope of these planning studies, we are 
seeking comments on: (1) the assumptions (e.g., weather forecast, load 
forecast, transmission voltage levels, generator types, multi-day low 
wind, solar event, etc.) used in modeling of concurrent outages due to 
extreme heat and cold weather events; (2) what assumptions should be 
included when performing modeling and planning for generators sensitive 
to extreme heat and cold; (3) how the impact of loss of generators 
sensitive to extreme heat and cold should be factored into long-term 
planning; (4) the extent of neighboring systems' or planning areas' 
outages that should be modeled in transmission planning studies; and 
(5) whether a certain threshold of penetration of wind, solar 
generation, and natural gas generators should trigger additional 
analyses.
4. Sensitivity Analysis
    73. As part of its revisions to TPL-001-5.1, NERC should establish 
a requirement for sensitivity analysis for

[[Page 38032]]

transmission planners and planning coordinators to consider system 
models and sensitivity cases when assessing extreme heat and extreme 
cold weather. A sensitivity case is a variation from the base case that 
helps a transmission planner to determine if the results are sensitive 
to changes in the inputs. Reliability Standard TPL-001-5.1, Requirement 
R2.1.4 requires that sensitivity power flow cases be used to 
demonstrate the impact of changes to the basic assumptions used in the 
models for system peak load or system off-peak load. These changes 
include, among other things, conditions that vary with temperature; 
specifically, load, generation, and system transfers.\106\ While 
requiring the variation of one of the specified conditions to 
demonstrate a measurable change, it does not require the simultaneous 
variation of load, generation and transfers necessary to model 
conditions that reflect extreme heat or cold weather conditions, thus 
potentially causing major reliability issues (i.e., widespread outages, 
cascading, etc.) to remain overlooked and undetected in the planning 
horizon. To model the effect of extreme heat or cold weather, demand 
probability scenario cases (90/10, 80/20, 50/50),\107\ generators that 
are affected by these events (i.e., wind tripping off, solar dropping 
off, gas plants not operational due to gas restrictions/freeze-offs, 
etc.), and transfer levels need to be defined and modeled in 
sensitivity analyses.
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    \106\ To effectively model the Bulk-Power System, transmission 
planners need make assumptions that create scenarios that are valid, 
realistic, and defendable. See North American Transmission Forum, 
TPL-001-4 Reference Document, at 8-9 (Aug. 2, 2021), https://www.natf.net/docs/natf/documents/resources/planning-and-modeling/natf-tpl-001-4-reference-document.pdf. Specifically, appropriate 
assumptions and corresponding model adjustments need to be made 
regarding load (demand), generation (particularly that of 
renewables), and transfers (power flows between regions or zones). 
See National Renewable Energy Laboratory, Report: The Evolving Role 
of Extreme Weather Events in the U.S. Power System with High Levels 
of Variable Renewable Energy (Dec. 2021), https://www.nrel.gov/docs/fy22osti/78394.pdf.
    \107\ Demand scenario cases are given designations based on the 
percent probability the actual system's peak demand for the period 
under study will be above or below certain level. For example, for a 
90/10 case, the system demand is modeled at a level that there is a 
90% probability the actual system demand will be below that level 
and a 10% probability that the actual system demand will be above 
that level. Other designations follow similarly using different 
percentages.
---------------------------------------------------------------------------

    74. Therefore, we seek comment on: (1) requiring transmission 
planners and planning coordinators to assess reliability in the 
planning horizon for sensitivity cases in which multiple inputs, e.g., 
load and generator failures, change simultaneously during extreme heat 
and cold events; and (2) the range of factors and the number of 
sensitivity cases that should be considered to ensure reliable 
planning.
5. Modifications to the Traditional Planning Approach
    75. In modifying TPL-001-5.1, we propose to direct NERC to consider 
planning methods and techniques that diverge from past Reliability 
Standard requirements.\108\ Reliability Standard TPL-001-5.1 is based 
on a deterministic approach, which uses planned contingencies and 
definite performance criteria to study system response to various 
conditions. This approach yields accurate planning when the power 
supply is highly dispatchable, weather is predictable, and near-record 
peak demand is reached only a few days a year.\109\ However, the 
current planning approach applied in Reliability Standard TPL-001-5.1 
likely is not sufficient to accurately characterize the reliability 
risk from extreme heat and cold weather given the high degree of 
uncertainty inherent in predicting severe weather and its impact on 
generation resources, transmission, and load.
---------------------------------------------------------------------------

    \108\ We are not making a proposed finding at this time that 
modifications to the traditional planning approach are necessary to 
properly plan for extreme weather. Nonetheless, there is sufficient 
concern such that we believe NERC should consider alternative 
approaches when developing a new or modified Reliability Standard in 
response to a final rule in this proceeding.
    \109\ June 1, 2021 Tr. 31 (Barton).
---------------------------------------------------------------------------

    76. An alternative to the deterministic approach is to use 
probabilistic approaches in transmission planning. Probabilistic 
transmission planning captures random uncertainties in power system 
planning, including those in load forecasting, generator performance, 
and failures of system equipment. The probabilistic method is not 
intended to replace the deterministic criterion but adds one more 
dimension to enhance the transmission planning process.\110\
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    \110\ IEEE Explore, Probabilistic Planning of Transmission 
Systems: Why, How and an Actual Example, at 1 (July 2008), https://ieeexplore.ieee.org/document/4596093.
---------------------------------------------------------------------------

    77. NERC has recognized the need to incorporate probabilistic 
approaches into planning activities. For example, NERC's Probabilistic 
Assessment Working Group develops probabilistic analysis that 
contributes to NERC's Long-Term Reliability Assessment every other 
year. NERC is also investigating the development of probabilistic 
methods to study resource adequacy, energy sufficiency, and 
transmission adequacy for reliable delivery in composite reliability 
studies as well as to develop enhanced reliability metrics.\111\
---------------------------------------------------------------------------

    \111\ NERC Post-Technical Conference Comments 3.
---------------------------------------------------------------------------

    78. Therefore, to ensure reliable planning and operations in 
response to extreme heat and cold events, we believe that a new or 
modified approach may be beneficial to capture these events during the 
planning process. The new approach could include elements of both 
deterministic and probabilistic approaches to assess reliability 
outcomes. For example, the January 2018 South Central Cold Weather 
Event in the South Central part of the country was a near-miss where 
MISO would have been required to perform firm load shed if its next-
worst contingency occurred (i.e., outage of 1,163 MW generation in MISO 
South). The load shed would have been needed to alleviate low voltages 
at many locations that would have been significantly below their limits 
due to the failure of almost 200 generating units. Including scenarios 
in the planning process in which generator failures are 
probabilistically evaluated could result in a planning approach better 
prepared to ensure reliable outcomes compared to the existing planning 
requirements under Reliability Standard TPL-001-5.1.
    79. One option to modify the existing planning approach would be to 
expand the required deterministic studies to include probabilistically 
developed scenarios. Therefore, we seek comments on industry's 
experience and opinion on combining or layering probabilistic and 
deterministic approaches when planning for extreme heat and cold 
weather conditions in the context of Reliability Standard TPL-001-5.1. 
Specifically, we seek comments on the use of the proposed hybrid 
planning approach and: (1) the assumptions from the deterministic and 
probabilistic approaches that should be applied to study extreme heat 
and cold weather events; (2) the potential planning challenges from 
combining the two planning approaches; (3) the costs associated with 
adjustments to the currently applied deterministic approach; (4) the 
implementation period necessary for proposed changes; and (5) the 
reliability benefits that could result.
6. Coordination Among Planning Coordinators and Transmission Planners 
and Sharing of Study Results
    80. Reliability Standard TPL-001-5.1 cross-refences Reliability 
Standard MOD-032-1 (Data for Power System Modeling and Analysis), which 
establishes consistent modeling data requirements and reporting 
procedures

[[Page 38033]]

for development of planning horizon cases necessary to support analysis 
of the reliability of the interconnected transmission system. 
Reliability Standard MOD-032-1 ensures adequate means of data 
collection for transmission planning. It requires each balancing 
authority, generator owner, load serving entity, resource planner, 
transmission owner, and transmission service provider to provide 
steady-state, dynamic, and short circuit modeling data to its 
transmission planner(s) and planning coordinator(s). The modeling data 
is then shared pursuant to the data requirements and reporting 
procedures developed by the transmission planner and planning 
coordinator as set forth in Reliability Standard TPL-001-5.1, 
Requirement R1.
    81. While balancing authorities and other entities must share 
system information and study results with their transmission and 
planning coordinator pursuant to Reliability Standards MOD-032-1 and 
TPL-001-5.1 as described above, there is no required sharing of such 
information--or required coordination--among planning coordinators and 
transmission planners with transmission operators, transmission owners, 
and generator owners, thus limiting the benefits of additional 
modeling. Sharing system information and study results and enhancing 
coordination among these entities for extreme heat and cold weather 
events could result in more representative planning models by better: 
(1) integrating and including operations concerns (e.g., lessons 
learned from past issues including corrective actions and projected 
outcomes from these actions, evolving issues concerning extreme heat/
cold) in planning models; and (2) conveying reliability concerns from 
planning studies (e.g., potential widespread cascading, islanding, 
significant loss of load, blackout, etc.) as they pertain to extreme 
heat or cold.
    82. Therefore, as part of its revisions, NERC should require system 
information and study results sharing, and coordination among planning 
coordinators and transmission planners with transmission operators, 
transmission owners, and generator owners for extreme heat and cold 
weather events. To better understand the benefits of the suggested 
actions, we are inviting comments on: (1) the parameters and timing of 
coordination and sharing; (2) specific protocols that may need to be 
established for efficient coordination practices; and (3) potential 
impediments to the proposed coordination efforts.

C. Implement a Corrective Action Plan If Performance Standards Are Not 
Met

    83. Pursuant to FPA 215(d)(5), we propose to direct NERC to modify 
Reliability Standard TPL-001-5.1 to require corrective action plans 
that include mitigation for any instances where performance 
requirements for extreme heat and cold events are not met. Under the 
currently effective Reliability Standard TPL-001-4, planning 
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 develop 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.\112\ 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.
---------------------------------------------------------------------------

    \112\ Reliability Standard TPL-001-4, Requirements R3.3.5 and 
R4.4.5 require computer simulation analyses of extreme events listed 
in Table 1 of the standard (some listed are examples and are not 
definitive), and if the analysis concludes there is Cascading caused 
by the occurrence of extreme events, an evaluation of possible 
actions designed to reduce the likelihood or mitigate the 
consequences and adverse impacts of the event(s) shall be conducted.
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    84. Consistent with the existing requirements of TPL-001-5.1, we 
believe it is appropriate to provide responsible entities with the 
flexibility to determine the best actions to include in their 
corrective action plan to remedy any identified deficiencies in 
performance. Examples of actions that could be included in a corrective 
action plan are planning for additional contingency reserves or 
implementing new energy efficiency programs to decrease load, 
increasing intra- and inter-regional transfer capabilities, 
transmission switching, or adjusting transmission and generation 
maintenance outages based on longer-lead forecasts. Well planned 
mitigation and corrective actions that account for some of these 
contingencies will minimize loss of load and improve resilience during 
extreme heat and cold weather events.
    85. In particular, increases in interregional transfer capability 
could be considered as one option to address potential reliability 
issues during extreme weather events. Such transfer capability would 
allow an entity in one region with available energy to assist one or 
more entities in another region that is experiencing an energy 
shortfall due to the extreme weather event. Increasing interregional 
transfer capability may be a particularly robust option for planning 
entities attempting to mitigate the risks associated with concurrent 
generator outages over a wide area.\113\
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    \113\ In this NOPR we refer to interregional transfer capability 
strictly in the context of improving the reliability of the Bulk-
Power System through improved transmission system planning and 
associated modifications to NERC's Reliability Standards. As such, 
our proposals here are distinct from the requirements for 
interregional coordination and cost allocation for public utility 
transmission providers. See Transmission Planning and Cost 
Allocation by Transmission Owning and Operating Public Utilities, 
Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 FERC ] 61,051 
(2011), order on reh'g, Order No. 1000-A, 77 FR 32184 (May 31, 
2012), 139 FERC ] 61,132, order on reh'g and clarification, Order 
No. 1000-B, 77 FR 64890 (Oct. 24, 2012), 141 FERC ] 61,044 (2012), 
aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 
2014).
---------------------------------------------------------------------------

    86. Recent events have shown that interregional transfer capability 
can be critical to maintaining reliability during extreme weather 
events. For example, during the 2021 Cold Weather Event in Texas and 
the South Central United States, SPP and MISO imported power from other 
balancing authorities to make up for their increasing load levels and 
generation shortfalls, because the eastern part of the Eastern 
Interconnection did not have the same arctic weather conditions. 
Specifically, MISO was able to import large amounts of power from 
neighbors to the east (e.g., PJM), and SPP was able to transfer some of 
that power through MISO into its region. Those east-to-west transfers 
into MISO peaked at nearly 13,000 MW.\114\ PJM had additional energy 
available to be transferred but could not facilitate the transfer due 
to internal congestion in neighboring systems.\115\
---------------------------------------------------------------------------

    \114\ 2021 Cold Weather Event Report at 15.
    \115\ PJM Post-Conference Comments at 19-20.
---------------------------------------------------------------------------

    87. Recent events have also shown that the loss of interregional 
transfer capability can have significant implications for system 
reliability during extreme weather events. For instance, during the 
August 2020 California Heatwave Event, there was a reduction in the 
transfer capability through the Northwest AC Intertie by as much as 
1,250 MW due to another extreme weather event that occurred earlier in 
2020 which damaged transmission facilities in the northwest part of the 
Western Interconnection. The transfer capability of the intertie 
linking

[[Page 38034]]

Canadian and U.S. power systems was also reduced by up to 750 MW due to 
other planned maintenance outages, further limiting the ability to 
transfer energy from the north to the load centers in the south.\116\
---------------------------------------------------------------------------

    \116\ 2020 Heat Event Report at 6.
---------------------------------------------------------------------------

    88. Thus, we believe that there may be potential benefits in better 
incorporating interregional transfer capability into corrective action 
plans, where warranted and encourage NERC to consider establishing 
requirements that appropriately recognize the value of interregional 
transfer capability.
    89. To ensure corrective action plans are developed and implemented 
in a timely fashion, we invite comments on the timeframe for developing 
such corrective action plans and sharing of the corrective actions with 
other interconnected planning entities.

D. Other Extreme Weather-Related Events and Issues

    90. While the focus of this NOPR is on extreme heat and cold 
weather events, we recognize that long-term drought, particularly when 
occurring in conjunction with high temperatures, could also pose a 
serious risk to Bulk-Power System reliability over a wide geographical 
area.\117\ In particular, we are concerned that drought may cause or 
contribute to conditions that affect reliable operation of transmission 
systems such as transmission outages, reduced plant efficiency, and 
reduced generation capacity.
---------------------------------------------------------------------------

    \117\ DOE, Impacts of Long-term Drought on Power Systems in the 
U.S. Southwest, at 5, https://www.energy.gov/sites/prod/files/Impacts%20of%20Long-term%20Drought%20on%20Power%20Systems%20in%20the%20US%20Southwest%20%E2%80%93%20July%202012.pdf.
---------------------------------------------------------------------------

    91. Some examples of recorded events of reduced power production 
from drought were seen in the Midwest in 2007 forcing nuclear and coal-
fired plants to shut down and curtail operations and along the 
Mississippi River in 2006, which affected nuclear plants in Illinois 
and Minnesota.\118\ According to a study conducted by NOAA's drought 
task force, climate change has intensified the drought conditions 
gripping the Southwestern United States, the region's most severe on 
record, with precipitation at the lowest 20-month level documented 
since 1895.\119\ The study indicates that the drought that emerged in 
early 2020 in California, Nevada and the ``Four Corners'' states of 
Arizona, Utah, Colorado and New Mexico has led to unprecedented water 
shortages in reservoirs across the region, while exacerbating 
devastating western wildfires over the past two years.\120\
---------------------------------------------------------------------------

    \118\ Id. at 6.
    \119\ NOAA, Assessment Report the 2020-2021 Southwestern U.S. 
Drought, at 6, https://cpo.noaa.gov/MAPP/DTF4SWReport.
    \120\ Reuters, Southwest U.S. Drought, Worst in a Century, 
Linked by NOAA to Climate Change (Sept. 21, 2021), https://
www.reuters.com/business/environment/southwest-us-drought-worst-
century-linked-by-noaa-climate-change-2021-09-21/
#:~:text=The%20drought%20emerged%20in%20early,two%20years%2C%20the%20
report%20noted.
---------------------------------------------------------------------------

    In addition, NERC's 2022 Summer Reliability Assessment concludes 
that in 2022 drought threatens wide areas of North America, mainly in 
the western United States and Texas, resulting in challenges to area 
electricity supplies.\121\
---------------------------------------------------------------------------

    \121\ NERC, 2022 Summer Reliability Assessment, at 5 (May 2022), 
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/
NERC_SRA_2022.pdf.
---------------------------------------------------------------------------

    92. Therefore, we seek 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 system planning requirements. 
These comments will assist the Commission in determining whether the 
final rule should direct that NERC further modify Reliability Standard 
TPL-001-5.1 to require transmission planners to conduct transmission 
planning assessments of the effects of drought conditions on 
transmission system operations.
    93. Finally, we invite comments on whether other extreme weather 
events with significant impact on the reliability of the Bulk-Power 
System (e.g., tornadoes, hurricanes) could also be considered and 
modeled in the future to improve system performance during these 
events.

V. Information Collection Statement

    94. The information collection requirements contained in this 
Notice of Proposed Rulemaking are subject to review by the Office of 
Management and Budget (OMB) under section 3507(d) of the Paperwork 
Reduction Act of 1995.\122\ OMB's regulations require approval of 
certain information collection requirements imposed by agency 
rules.\123\ Upon approval of a collection of information, OMB will 
assign an OMB control number and expiration date. Respondents subject 
to the filing requirements of this rule will not be penalized for 
failing to respond to this collection of information unless the 
collection of information displays a valid OMB control number.
---------------------------------------------------------------------------

    \122\ 44 U.S.C. 3507(d).
    \123\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    95. The proposal to direct NERC modify existing Reliability 
Standard TPL-001 (Transmission System Planning Performance 
Requirements), is covered by, and already included in, the existing 
OMB-approved information collection FERC-725 (Certification of Electric 
Reliability Organization; Procedures for Electric Reliability 
Standards; OMB Control No. 1902-0225),under Reliability Standards 
Development.\124\ The reporting requirements in FERC-725 include the 
ERO's overall responsibility for developing Reliability Standards, such 
as the TPL-001 Reliability, which is designed to ensure the BES will 
operate reliably over a broad spectrum of system conditions and 
following a wide range of probable contingencies.\125\ The Commission 
will submit to OMB a request for a non-substantive revision of FERC-725 
in connection with this NOPR.
---------------------------------------------------------------------------

    \124\ Reliability Standards Development as described in FERC-725 
covers standards development initiated by NERC, the Regional 
Entities, and industry, as well as standards the Commission may 
direct NERC to develop or modify.
    \125\ Reliability Standard TPL-001-4, Purpose.
---------------------------------------------------------------------------

VI. Environmental Assessment

    96. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\126\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment. Included in the exclusion are rules that are clarifying, 
corrective, or procedural or that do not substantially change the 
effect of the regulations being amended.\127\ The actions proposed here 
fall within this categorical exclusion in the Commission's regulations.
---------------------------------------------------------------------------

    \126\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. 
& Regs., ] 30,783 (1987) (cross-referenced at 41 FERC ] 61,284).
    \127\ 18 CFR 380.4(a)(2)(ii) (2021).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act Certification

    97. The Regulatory Flexibility Act of 1980 (RFA) \128\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \128\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

    98. We are proposing only to direct NERC, the Commission-certified 
ERO, to develop modified Reliability Standards that require enhanced 
long-term system transmission planning designed to prepare for extreme 
heat and cold

[[Page 38035]]

weather conditions.\129\ Therefore, this Notice of Proposed Rulemaking 
will not have a significant or substantial impact on entities other 
than NERC. Consequently, the Commission certifies that this Notice of 
Proposed Rulemaking will not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \129\ Cf. Cyber Sec. Incident Reporting Reliability Standards, 
Notice of Proposed Rulemaking, 82 FR 61499 (Dec. 28, 2017), 161 FERC 
] 61,291 (2017) (proposing to direct NERC to develop and submit 
modifications to the NERC Reliability Standards to improve mandatory 
reporting of Cyber Security Incidents, including incidents that 
might facilitate subsequent efforts to harm the reliable operation 
of the BES); Internal Network Sec. Monitoring for High and Medium 
Impact Bulk Elec. Sys. Cyber Sys., 178 FERC ] 61,038 (2020) 
(proposing to direct NERC to new or modified Reliability Standards 
that require internal network security monitoring within a trusted 
Critical Infrastructure Protection networked environment for high 
and medium impact Bulk Electric System Cyber Systems).
---------------------------------------------------------------------------

    99. Any Reliability Standards proposed by NERC in compliance with 
this rulemaking will be considered by the Commission in future 
proceedings. As part of any future proceedings, the Commission will 
make determinations pertaining to the Regulatory Flexibility Act based 
on the content of the Reliability Standards proposed by NERC.

VIII. Comment Procedures

    100. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due August 26, 2022. Comments must 
refer to Docket No. RM22-3-000, and must include the commenter's name, 
the organization they represent, if applicable, and address in their 
comments. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.
    101. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's website at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software must be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    102. Commenters that are not able to file comments electronically 
may file an original of their comment by USPS mail or by courier-or 
other delivery services. For submission sent via USPS only, filings 
should be mailed to: Federal Energy Regulatory Commission, Office of 
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of 
filings other than by USPS should be delivered to: Federal Energy 
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.

IX. Document Availability

    103. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the Commission's Home Page (http://www.ferc.gov). At 
this time, the Commission has suspended access to the Commission's 
Public Reference Room due to the President's March 13, 2020 
proclamation declaring a National Emergency concerning the Novel 
Coronavirus Disease (COVID-19).
    104. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    105. User assistance is available for eLibrary and the Commission's 
website during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at 
[email protected].
    By direction of the Commission. Commissioner Danly is concurring 
with a separate statement attached. Commissioner Clements is concurring 
with a separate statement attached. Commissioner Phillips is concurring 
with a separate statement attached.

    Issued: June 16, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.
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)
    DANLY, Commissioner, concurring:
    1. I concur in today's notice of proposed rulemaking directing the 
North American Electric Reliability Corporation (NERC) to submit 
modifications to Reliability Standard TPL-001-5.1 to address 
reliability concerns related to transmission system planning.\130\ It 
will take over two years, at a minimum, from this notice of proposed 
rulemaking (NOPR) to the ultimate implementation of any such changes. 
Reliability Standard development is neither swift nor agile, and this 
NOPR will not, indeed cannot, timely address the projected risk of 
widespread blackouts this summer,\131\ nor can they be in place quickly 
enough to address future summer and winter reliability challenges over 
the next couple of years. Yet, I agree it is an important (albeit 
small) step to establish mandatory and enforceable compliance 
obligations to promote proactive planning for weather-related events.
---------------------------------------------------------------------------

    \130\ Transmission Sys. Planning Performance Requirements for 
Extreme Weather, 179 FERC ] 61,195 (2022).
    \131\ Chairman Glick says that I am ``prone to hyperbole'' when 
I warn that blackouts are the likely outcome of the majority's 
misguided policies to prop up renewables at the expense of 
competitive markets and existing fossil resources. Rich Heidorn Jr., 
Summer Forecasts Spark Warnings of `Reliability Crisis' at FERC, RTO 
Insider (May 19, 2022), https://www.rtoinsider.com/articles/30170-summer-forecasts-spark-warnings-reliability-crisis-ferc. Chairman 
Glick appears to be confusing ``hyperbole'' with ``reality.'' 
California and Texas have already experienced blackouts. Over two-
thirds of the nation faces ``elevated [reliability] risk'' this 
summer. Ethan Howland, FERC commissioners respond to elevated power 
outage risks across two-thirds of US, Utility Dive (May 20, 2022), 
https://www.utilitydive.com/news/ferc-nerc-power-outage-risks-summer-drought/624111/ (``At its monthly meeting Thursday, Federal 
Energy Regulatory Commission members dissected the North American 
Electric Reliability Corp.'s warning that roughly two-thirds of the 
United States faces [sic] heightened risks of power outages this 
summer.'').
---------------------------------------------------------------------------

    2. The NOPR makes use of, indeed bases our action upon, an ever-
growing narrative: reliability challenges arise primarily from weather-
related events.\132\ But even if one were to grant that certain parts 
of the United States were experiencing statistically unusual weather 
when compared to historical baselines, that has absolutely nothing to 
do with whether the markets and regulated utilities are procuring

[[Page 38036]]

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\
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    \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.'').
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    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

[[Page 38037]]

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.

[[Page 38038]]

    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).
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    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.
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    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

[[Page 38039]]

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\
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    \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

[[Page 38040]]

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

[[Page 38041]]

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.'').
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    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.'').
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    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\
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    \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).
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    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

[[Page 38042]]

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.
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    \1\ Transmission System Planning Performance Requirements for 
Extreme Weather, 179 FERC ] 61,195 (2022) (NOPR).
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    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\
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    \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.'').
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    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\
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    \4\ NOPR at PP 51-56.
    \5\ See infra at PP 6-8.
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    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.'').
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    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\
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    \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).
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    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

[[Page 38043]]

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

[[Page 38044]]

work to be done.\19\ I look forward to examining all the comments as we 
seek to issue a final rule around these topics.
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    \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]
BILLING CODE 6717-01-P


