38020 Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 

1Paragraph (a)(3) of this section assumes that as 

the magnitude of the potential dose increases above 

that permitted under normal conditions, the 

probability that any individual will receive such a 

dose must decrease. The probabilities have been 

expressed in general terms to emphasize the 

approximate nature of the estimates that are to be 

made. The following values may be used as guides 

in estimating compliance with the criteria: Low— 

not more than one such failure/incident per year for 

each 10,000 exempt units distributed. Negligible— 

not more than one such failure/incident per year for 

each one million exempt units distributed. 

(xvi) Any additional information, 

including experimental studies and 

tests, requested by the Commission. 

(3) The Commission determines that 

the product meets the safety criteria in 

§ 32.34. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, the 

Commission may deny an application 

for a specific license under this section 

if the end uses of the product cannot be 

reasonably foreseen. 

§ 32.34 Items containing byproduct 

material incidental to production safety 

criteria. 

(a) An applicant for a license under 

§ 32.33 must demonstrate that the item 

is designed and will be manufactured so 

that: 

(1) In normal use, normal handling, 

and normal storage of the quantities of 

exempt items likely to accumulate in 

one location, including during 

marketing, distribution, installation, 

and/or servicing of the item, it is 

unlikely that: 

(i) The external radiation dose in any 

one year, or the committed dose 

resulting from the intake of radioactive 

material in any one year, to a suitable 

sample of the group of individuals 

expected to be most highly exposed to 

radiation or radioactive material from 

the item will exceed 50 mSv (5 mrem); 

and 

(ii) There will be a significant 

reduction in the effectiveness of the 

safety features of the item from wear 

and abuse. 

(2) In disposal of quantities of exempt 

items likely to accumulate in the same 

disposal site, it is unlikely that the 

external radiation dose in any one year, 

or the committed dose resulting from 

the intake of radioactive material in any 

one year, to a suitable sample of the 

group of individuals expected to be 

most highly exposed to radiation or 

radioactive material, will exceed 10 mSv 

(1 mrem). 

(3) In use, handling, storage, and 

disposal of the quantities of exempt 

products likely to accumulate in one 

location, including during marketing, 

distribution, installation, and/or 

servicing of the item, the probability is 

low that the safety features of the item 

would fail under such circumstances 

that a person would receive an external 

radiation dose or committed dose in 

excess of 5 mSv (500 mrem), and the 

probability is negligible that a person 

would receive an external radiation 

dose or committed dose of 100 mSv (10 

rem) or greater.1

(b) An applicant for a license under 

§ 32.33 must demonstrate that, even in 

unlikely scenarios of misuse, including 

those resulting in direct exposure to the 

item for 1,000 hours at an average 

distance of 1 meter and those resulting 

in dispersal and subsequent intake of 

10¥4 of the quantity of byproduct 

material (or in the case of tritium, an 

intake of 10 percent), a person will not 

receive an external radiation dose or 

committed dose in excess of 100 mSv 

(10 rem), and, if item is small enough 

to fit in a pocket, that the dose to 

localized areas of skin averaged over 

areas no larger than 1 square centimeter 

from carrying the item in a pocket for 

80 hours will not exceed 2 Sv (200 rem). 

§ 32.35 Conditions of licenses issued 

under § 32.33: Quality control, labeling, and 

reports of transfer. 

Each person licensed under § 32.33 

must: 

(a) Carry out adequate control 

procedures in the manufacture of the 

item to assure that each item meets the 

quality control standards approved by 

the Commission; 

(b) Label or mark each point of sale 

package and, if feasible, each unit. Each 

mark or label must contain the 

statement ‘‘CONTAINS RADIOACTIVE 

MATERIAL’’ and must identify the 

initial transferor of the item; and 

(c) Maintain records of all transfers 

and file a report with the Director of the 

Office of Nuclear Material Safety and 

Safeguards by an appropriate method 

listed in 10 CFR 30.6(a), including in 

the address: ATTN: Document Control 

Desk/Exempt Distribution. 

(1) The report must clearly identify 

the specific licensee submitting the 

report and include the license number 

of the specific licensee. 

(2) The report must indicate that the 

items are transferred for use under 10 

CFR 30.16 or equivalent regulations of 

an Agreement State. 

(3) The report must include the 

following information on items 

transferred to other persons for use 

under 10 CFR 30.16 or equivalent 

regulations of an Agreement State: 

(i) A description or identification of 

the type of each item and the model 

number(s); and 

(ii) The number of units of each type 

of product transferred during the 

reporting period by model number. 

(4)(i) The report, covering the 

preceding calendar year, must be filed 

on or before January 31 of each year. 

The licensee must separately include 

data for transfers in prior years not 

previously reported to the Commission. 

(ii) Licensees who permanently 

discontinue activities authorized by the 

license issued under § 32.33 must file a 

report for the current calendar year 

within 30 calendar days after ceasing 

distribution. 

(5) If no transfers of byproduct 

material have been made under § 32.33 

during the reporting period, the report 

must so indicate. 

(6) The licensee must maintain the 

record of a transfer for one year after the 

transfer is included in a report to the 

Commission. 

§ 32.303 [Amended] 

■ 5. In § 32.303, amend paragraph (b) by 

adding the references ‘‘32.33, 32.34,’’ in 

sequential order. 

Dated June 21, 2022. 

For the Nuclear Regulatory Commission. 

Brooke P. Clark, 

Secretary of the Commission. 

[FR Doc. 2022–13599 Filed 6–24–22; 8:45 am] 

BILLING CODE 7590–01–P 

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. 

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 


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Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 38021 

1 16 U.S.C 824o(d)(5). 

2Transmission 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. 

3The 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). 

4The 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). 

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. 

Æ Mail via U.S. Postal Service only: 

Addressed to: Federal Energy 

Regulatory Commission, Office of the 

Secretary, 888 First Street NE, 

Washington, DC 20426. 

Æ 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, mahmood.mirheydar@ferc.gov 

Milena Yordanova (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street NE, Washington, DC 

20426, (202) 502–6194, 

milena.yordanova@ferc.gov 

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 Reliability Technical Conference ................................................. 10 

C. Overview of Technical Conference Comments ......................................................................................................................... 13 

D. Cold Weather Reliability Standards .......................................................................................................................................... 18 

E. Reliability Standard TPL–001–4 (Transmission System Planning Performance Requirements) ........................................... 20 

III. The Need for Reform ........................................................................................................................................................................ 24 

A. Recent Events Show Changes in Weather Patterns Resulting in More Extreme Heat and Cold Weather Events ............... 24 

B. NERC Reliability Standards Do Not Require Planning To Minimize the Increasing Reliability Risks Associated With 

Anticipated Extreme Heat and Cold Weather Events ................................................................................................................ 37 

IV. Proposed Directives .......................................................................................................................................................................... 47 

A. Develop Benchmark Planning Cases Based on Major Prior Extreme Heat and Cold Weather Events ................................. 50 

B. Transmission System Planning for Extreme Heat and Cold Weather Events ......................................................................... 57 

1. Steady State and Transient Stability Analyses .................................................................................................................. 58 

2. Transmission Planning Studies of Wide-Area Events ....................................................................................................... 64 

3. Study Concurrent Generator and Transmission Outages .................................................................................................. 68 

4. Sensitivity Analysis ............................................................................................................................................................. 73 

5. Modifications to the Traditional Planning Approach ....................................................................................................... 75 

6. Coordination Among Planning Coordinators and Transmission Planners and Sharing of Study Results .................... 80 

C. Implement a Corrective Action Plan If Performance Standards Are Not Met ........................................................................ 83 

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 Commissioncertified 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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38022 Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 

5Technical 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). 

6Environmental 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). 

7NERC 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.’’ 

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-northwestamid-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 Southcentral United States to global warming-induced 

weather anomalies that are likely to continue to 

produce severe winter storm events). 

11This 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 MidAtlantic 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. 

12PJM, 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-eventsand-market-impacts-during-the-september-2013- 

heat-wave. 

13FERC, 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). 

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. 

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

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 BulkPower 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

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 BulkPower 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 BulkPower 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 


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Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 38023 

14See 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). 

15 16 U.S.C. 824o(e). 

16Rules 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). 

17N. 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). 

18 16 U.S.C. 824o(d)(5). 

19 18 CFR 39.5(g) (2021). 

20Climate 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. 

22Supplemental Notice of Technical Conference, 

Docket No. AD21–13–000, at 1, 3 (Mar. 15, 2021). 

23 Id. at 5. 

24Supplemental Notice of Technical Conference, 

Docket No. AD21–13–000, at 1, 3 (May 27, 2021) 

(attaching agenda). 

25Notice Inviting Post-Technical Conference 

Comments, Docket No. AD21–13–000, at 3, 5 (Aug. 

11, 2021). 

26See, e.g., California Independent System 

Operator Corporation (CAISO) Pre-Conference 

Comments at 3. 

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

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 weatherrelated 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

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 § 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

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

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 costeffective 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

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

C. Overview of Technical Conference 

Comments 

13. Commenters submitted more than 

50 sets of pre-conference and 20 postconference 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 


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38024 Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 

27Environmental Defense Fund and Columbia 

Law School’s Sabin Center for Climate Change Law 

Pre-Conference Comments at 4. 

28CAISO Pre-Conference Comments at 1–3; 

California Public Utilities Commission PreConference 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). 

30 ISO-New England Inc. Pre-Conference 

Comments at 10. 

31Midcontinent 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). 

33Pacific Gas and Electric Company PreConference Comments at 19–20. 

34MISO Post-Conference Comments at 20. 

35PJM Post-Conference Comments at 21. 

36CAISO Post-Conference Comments at 10. 

37NERC 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). 

39N. 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. 

41NERC Glossary defines ‘‘Planning Assessment’’ 

as ‘‘documented evaluation of future Transmission 

System performance and Corrective Action Plans to 

remedy identified deficiencies.’’ 

42 Id. 

43Reliability Standard TPL–001–4, Purpose. 

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

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

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

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

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

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

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

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 


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44Reliability 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). 

45See Reliability Standard TPL–001–4, 

Requirement 2.1 (Near-Term Transmission Planning 

Horizon) and Requirement R.2.2 (Long-Term 

Transmission Planning Horizon). 

46FERC 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/ 

ReportontheSouthwestColdWeatherEventfrom

February2011Report.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. 

48PJM, 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-eventsand-market-impacts-during-the-september-2013- 

heat-wave. 

49 Id. at 4. 

50Under demand response programs, retail 

customers volunteer and are paid to reduce their 

electricity use when requested. 

51PJM Heat Wave Analysis at 5. 

52NERC, 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. 

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

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 prespecified 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 preselected 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 Table1, Steady State & Stability Performance 

Extreme Events, states that steady state 

analysis should be conducted for widearea 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 catchall 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

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

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 


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53 Id. at 4. 

54 Id. at iii. 

55FERC 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. 

57Western 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. 

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

60 Id. at 9. 

61 Id. 

62 Id. at 127 n.197. 

63 Id. at 10. 

64PJM 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. 

65Climate Signals, Northwest Pacific Heat Wave 

June 2021 (Oct. 2021), https://

www.climatesignals.org/events/northwest-pacificheat-wave-june-2021#/more. 

66Sjoukje 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.worldweather

attribution.org/wp-content/uploads/NW-USextreme-heat-2021-scientific-report-WWA.pdf. 

67NOAA website, Climate Data Online (NOAA 

website, Climate Data Online), https://

www.ncdc.noaa.gov/cdo-web/. 

68EPA Climate Change Indicators. 

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

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. 

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

31. More recently, in February 2021, 

Texas and the South-Central United 

States experienced the 2021 Cold 

Weather Event, the fourth cold-weatherrelated 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

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

33. Finally, in June 2021 the Pacific 

Northwest experienced another recordbreaking 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

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, 


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69NOAA website, Climate Data Online. 

70NOAA, Climate Program Office, Research Links 

Extreme Cold Weather in the United States to Arctic 

Warming, https://cpo.noaa.gov/InteragencyPrograms/NIHHIS/ArtMID/6409/ArticleID/2369/ 

Research-Links-Extreme-Cold-Weather-in-theUnited-States-to-ArcticWarming?msclkid=f9ad03bcc

7c911ecba22ebf3e1ead5d9. 

71NOAA website, Climate Data Online. 

72Contingency 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. 

73 2018 Cold Weather Event Report at 12–13. 

74ERCOT, Nodal Operating Guide, at 137 (Jan. 1, 

2022), https://www.ercot.com/files/docs/2021/12/ 

21/Nodal%20Operating%20Guide.pdf. 

75Fuel 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. 

and more extreme heat conditions in 

cities.69

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

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 longerlead 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. 

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-beeffective 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 widespread 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

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. 

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 gasfired generating units due to fuel 

issues 75 and a pipeline equipment 

failure, and 27% were wind generation 

due to blade icing.76

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. 


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77NERC, About Alerts, https://www.nerc.com/pa/ 

rrm/bpsa/Pages/About-Alerts.aspx. 

78NERC, 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. 

79NERC, 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,insufficient%20amounts%20of

%20energy%20on. 

80NERC Post-Technical Conference Comments at 

7. 

81NERC, 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. 

82NERC, 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.’’). 

83For 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. 

84Order No. 693, 118 FERC ¶ 61,218 at P 186; 

Reliability Standards for Physical Sec. Measures, 

146 FERC ¶ 61,166 at P 13. 

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. 

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

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

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

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 weatherrelated events. 

49. Below we provide additional 

context for these three proposed 

directives and describe reliability 

concerns and potential options for 


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85See Reliability Standard TPL–001–5.1 

(Transmission System Planning Performance 

Requirements), Requirements R1 through R8. 

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-in50 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. 

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 


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86NERC, 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%2520

Quality%2520of%2520Analysis%2520(OC).pdf. 

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. 

90Reliability Standard MOD–032–1, 

Requirements R1 and R2. 

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). 

92Reliability 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. 

93Reliability Standard TPL–001–5.1, Table 1, 

Steady State & Stability Performance Extreme 

Events, Section 3(a)(i). 

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

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

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. 

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

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

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. 


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94MIT News, Preventing the Next Blackout (Dec. 

5, 2017), https://news.mit.edu/2017/mit-studyclimate-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. 

95The 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. 

96Polar 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. 

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%20

Vulnerabilities%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. 

103Temperature 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. 

105A 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. 

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

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. 

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 shortterm, 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

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. 

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 


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106To 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/natftpl-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. 

108We 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). 

110 IEEE Explore, Probabilistic Planning of 

Transmission Systems: Why, How and an Actual 

Example, at 1 (July 2008), https://

ieeexplore.ieee.org/document/4596093. 111NERC Post-Technical Conference Comments 3. 

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. 

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. 

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

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

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 


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112Reliability 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. 

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). 

114 2021 Cold Weather Event Report at 15. 

115PJM Post-Conference Comments at 19–20. 

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. 

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 longerlead 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

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

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 


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116 2020 Heat Event Report at 6. 

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%20

on%20Power%20Systems%20in%20the%20US%

20Southwest%20%E2%80%93%20

July%202012.pdf. 

118 Id. at 6. 

119NOAA, Assessment Report the 2020–2021 

Southwestern U.S. Drought, at 6, https://

cpo.noaa.gov/MAPP/DTF4SWReport. 

120Reuters, 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-centurylinked-by-noaa-climate-change-2021-09-21/

#:∼:text=The%20drought%20emerged%20

in%20early,two%20years%2C%20

the%20report%20noted. 

121NERC, 2022 Summer Reliability Assessment, 

at 5 (May 2022), https://www.nerc.com/pa/RAPA/

ra/Reliability%20Assessments%20DL/NERC_SRA_

2022.pdf. 

122 44 U.S.C. 3507(d). 

123 5 CFR 1320.11. 

124Reliability 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. 

125Reliability Standard TPL–001–4, Purpose. 

126Regulations 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). 

128 5 U.S.C. 601–612. 

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

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 BulkPower 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. 

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

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

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. 

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. 

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. 

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. 

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 


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129Cf. 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). 

130Transmission Sys. Planning Performance 

Requirements for Extreme Weather, 179 FERC 

¶ 61,195 (2022). 131Chairman 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-crisisferc. Chairman Glick appears to be confusing 

‘‘hyperbole’’ with ‘‘reality.’’ California and Texas 

have already experienced blackouts. Over twothirds 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-nercpower-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.’’). 

132See Chairman Glick (@RichGlickFERC), 

Twitter (May 19, 2022, 11:13 a.m.), https://

twitter.com/RichGlickFERC/status/ 

1527306459263881223?s=20&t=3a4C1cac3nmFkjZyvoUDA (‘‘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/energyenvironment/california-electricity-shortage.html. 

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. 

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 ferconlinesupport@ferc.gov, 

or the Public Reference Room at (202) 

502–8371, TTY (202)502–8659. Email 

the Public Reference Room at 

public.referenceroom@ferc.gov. 

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. 

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 


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133See 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. 

134See, 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-ResourcesAssessment.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-firmgeneration-resources-to-cover-peak-load-insummer-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-inpjm-whitepaper.ashx (addressing renewable 

integration). 

135See 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/presentationreport-2022-summer-energy-market-and-reliabilityassessment (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.’’). 

136U.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. 

137Ethan 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-plantowners-seek-to-retire-power-in-pjm/620781/. 

138See 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.’’). 

139See, e.g., Algonquin Gas Transmission, LLC, 

174 FERC ¶ 61,126 (2021) (Danly and Christie, 

Comm’rs, dissenting). 

140Matt 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-crisisschwarzman/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.’’). 

1One Time Informational Reports on Extreme 

Weather Vulnerability Assessments, 179 FERC 

¶ 61,196 (2022). 

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

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 weatherdependent resources with gas 

generators, largely dependent on just-intime 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. 

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. 

lllllllllllllllllll

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. 

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 


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2Reliability 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). 

3See Extreme Weather NOPR at PP 18–19 

(discussing Cold Weather Reliability Standards, 176 

FERC ¶ 61,119, at PP 1, 3 (2021)). 

4See 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. 

5See 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). 

6NERC, 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. 

7See Extreme Weather NOPR at PP 90–92 

(discussing the anticipated impacts of drought on 

the electricity system); infra P 8. 

8Building for the Future Through Electric 

Regional Transmission Planning and Cost 

Allocation and Generator Interconnection, 179 

FERC ¶ 61,028 (2022) (Regional Planning NOPR). 

9Severe 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). 

10While 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. 

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 longterm 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. 

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 costeffective 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. 

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. 

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. 

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. 


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11See, 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’’). 

12Comments of the Oregon Public Utility 

Commission, Docket No. AD21–13, at 2 (filed Apr. 

14, 2021). 

13Extreme Weather NOPR at P 52. 

14See 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’’). 

15See 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’’). 

16See 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.’’). 

17See 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. 

19Regional Planning NOPR, 179 FERC ¶ 61,028. 

20See Docket Nos. AD21–13 and AD21–14. 

21See Docket No RM21–17. 

22While this statement highlights key priority 

areas for further inquiry, it is not intended to be 

exclusive. See supra n. 10. 

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. 

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. 

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

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 longterm 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. 

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 


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23See 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). 

24Pfeifenberger 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-toImproved-Interregional-Transmission-Planning_

V4.pdf; see also id. at 2, Table 1, Summary of Select 

Recent Interregional Transmission Studies. 

25Post-Conference Comments of Eversource 

Energy, Docket No. AD21–13, at 6–7 (filed Sept. 27, 

2021). 

26See Pfeifenberger et al. at 4–5 (summarizing 

barriers to interregional transmission planning and 

development). 

27See, 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 bidirectional transfer capability’’ would facilitate 

‘‘interregional coordination’’). 

28Post-Conference Comments of American 

Electric Power, Docket No. AD21–13, at 10 (filed 

Sept. 27, 2021). 

29 Id. at 9–10. 

30 Id. at 9. 

31 Id. 

32Chao 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. 

34NERC 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. 

events, accounting for the possibility of 

common mode failures or other 

correlated outages. 

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

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. 

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

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 authorityspecific 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

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 nonRTO-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 nonRTO 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 flowbased method of transmission method,34

with most entities in the Western 


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38040 Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 

35See Joint Comments of Arizona Public Service 

Company and Public Service Company of Colorado, 

Docket No. AD21–14, at 5–6 (filed Jan. 31, 2022). 

36 Id. at 5. 

37 Id. at 6. 

38See 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.’’). 

39Post-Conference Comments of Midcontinent 

Independent System Operator, Docket No. AD21– 

13, at 10 (filed Sept. 27, 2021). 

40 Id. 

41See, e.g., PJM Manual 37, Reliability 

Coordination § 4.1; Southwest Power Pool, 

Congestion Management & Communication 

Processes, 5, 12–13 (2013). 

42See pro forma OATT § 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). 

43See Technical Conference Tr., June 2, 2021, 

Docket No. AD21–13–000, at 67:21–23 (filed July 

22, 2021). 

44See 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). 

45See NERC, TLR Logs, available at https://

www.nerc.com/pa/rrm/TLR/Pages/TLR-Logs.aspx 

(last accessed June 14, 2022). 

46Post-Conference Comments of Midcontinent 

Independent System Operator, Docket No. AD21– 

13, at 11 (filed Sept. 27, 2021). 

47See, 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); PostConference 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). 

48See Post-Conference Comments of 

Midcontinent Independent System Operator, 

Docket No. AD21–13, at 10 (filed Sept. 27, 2021). 

49 Id. at 9, 14–15. 

Interconnection continuing to use the 

less efficient path-based method.35

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. 

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 preset 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

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. 

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

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 


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50 Id. at 11–12. 

51 Id. at 13. 

52 Id. at 11. 

53NERC 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. 

54See, 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.’’). 

55See, 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.’’). 

56See 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. 

59See 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). 

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 directlyconnected public utility neighbors (or 

non-jurisdictional transmission 

providers that provide reliability 

redispatch) prior to implementing TLR 

procedures.’’ 52

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. 

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

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. 

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

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 


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38042 Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 

1Transmission System Planning Performance 

Requirements for Extreme Weather, 179 FERC 

¶ 61,195 (2022) (NOPR). 

2On 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). 

3To 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.’’). 

4NOPR at PP 51–56. 

5See infra at PP 6–8. 

6NOPR 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.’’). 

8Building 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). 

9Transmission 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). 

10See Americans for a Clean Energy Grid, 

Planning for the Future: FERC’s Opportunity to 

Spur More Cost-Effective Transmission 

Infrastructure, https://cleanenergygrid.org/wpcontent/uploads/2021/01/ACEG_Planning-for-thea 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. 

lllllllllllllllllll

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. 

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 longterm 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

3. The NOPR proposes to direct NERC 

to modify Reliability Standard TPL– 

001–5.1 to require the development of 

benchmark planning cases based on past 

extreme heat and cold weather events.4

Currently, Reliability Standard TPL– 

001–5.1 does not prescribe specific 

benchmarks, and I believe determining 

and using the appropriate benchmark 

will lead to better planning. While 

extreme weather can be unpredictable, 

applying a suitable benchmark study 

should lead to understanding resource 

availability and load shedding 

requirements under harsh conditions. 

Indeed, using benchmarks may also 

improve interregional coordination 

when load shedding and cascading 

outages occur.5

4. 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. 

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

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 


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Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 38043 

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.’’). 

11See, 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. PostConference 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). 

12See 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. 

13FERC–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.’’). 

16See 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). 

17See, 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.’’). 

18See 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.’’). 

effect has been limited. Many 

commenters also point out the 

importance of adopting a minimum 

level of interregional transfer 

capability.11

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. 

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. 

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 countrywide.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. 

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 


jspears on DSK121TN23PROD with PROPOSALS1
38044 Federal Register / Vol. 87, No. 122 / Monday, June 27, 2022 / Proposed Rules 

19For 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. 1See 67 FR 70315 (November 22, 2002). 

work to be done.19 I look forward to 

examining all the comments as we seek 

to issue a final rule around these topics. 

For these reasons, I respectfully 

concur. 

lllllllllllllllllll

Willie L. Phillips, 

Commissioner. 

[FR Doc. 2022–13471 Filed 6–24–22; 8:45 am] 

BILLING CODE 6717–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R03–OAR–2021–0944; FRL–9174–01– 

R3] 

Air Plan Approval; Delaware; Control 

of Volatile Organic Compounds 

Emissions From Solvent Cleaning and 

Drying 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to approve a 

state implementation plan (SIP) revision 

submitted by the State of Delaware. This 

revision pertains to the reduction of 

volatile organic compounds (VOC) 

emissions from cold solvent cleaning 

operations. This action is being taken 

under the Clean Air Act (CAA). 

DATES: Written comments must be 

received on or before July 27, 2022. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–R03– 

OAR–2021–0944 at https://

www.regulations.gov, or via email to 

gordon.mike@epa.gov. For comments 

submitted at Regulations.gov, follow the 

online instructions for submitting 

comments. Once submitted, comments 

cannot be edited or removed from 

Regulations.gov. For either manner of 

submission, EPA may publish any 

comment received to its public docket. 

Do not submit electronically any 

information you consider to be 

confidential business information (CBI) 

or other information whose disclosure is 

restricted by statute. Multimedia 

submissions (audio, video, etc.) must be 

accompanied by a written comment. 

The written comment is considered the 

official comment and should include 

discussion of all points you wish to 

make. EPA will generally not consider 

comments or comment contents located 

outside of the primary submission (i.e., 

on the web, cloud, or other file sharing 

system). For additional submission 

methods, please contact the person 

identified in the FOR FURTHER

INFORMATION CONTACT section. For the 

full EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

https://www.epa.gov/dockets/ 

commenting-epa-dockets. 

FOR FURTHER INFORMATION CONTACT: 

Mallory Moser, Planning & 

Implementation Branch (3AD30), Air & 

Radiation Division, U.S. Environmental 

Protection Agency, Region III, 1650 

Arch Street, Philadelphia, Pennsylvania 

19103. The telephone number is (215) 

814–2030. Ms. Moser can also be 

reached via electronic mail at 

Moser.Mallory@epa.gov. 

SUPPLEMENTARY INFORMATION: On 

October 13, 2021, the Delaware 

Department of Natural Resources and 

Environmental Control (DNREC) 

submitted a revision to its SIP which 

comprises revisions to Title 7 of 

Delaware’s Administrative Code (7 DE 

Admin. Code) 1124 Section 33.0— 

Solvent Cleaning and Drying. The 

revision to 7 DE Admin. Code 1124 

Section 33.0 will reduce emissions of 

VOCs from cold solvent cleaning 

operations, thus reducing the formation 

of ground-level ozone. 

I. Background 

The revision consists of an 

amendment to 7 DE Admin. Code 1124, 

Control of Volatile Organic Compound 

Emissions, Section 33—Solvent 

Cleaning and Drying. Specifically, the 

amendment updates the solvent 

cleaning control requirements based 

upon the 2012 Ozone Transport 

Commission (OTC) Model Rule. 

The OTC, of which Delaware is a 

member, is an organization established 

by Congress under the CAA. Among 

other things, the OTC develops model 

rules for the member states to use to 

reduce the emissions of ground level 

ozone precursors. In 2001, the OTC 

released the 2001 Model Rule for 

Solvent Cleaning (2001 Model Rule). 

The 2001 Model Rule is the basis for the 

version of 7 DE Admin. Code 1124, 

Control of Volatile Organic Compound 

Emissions, Section 33—Solvent 

Cleaning and Drying currently in the 

approved Delaware SIP.1 After a release 

of the control techniques guideline 

(CTG): Industrial Cleaning Solvents by 

the EPA in 2006, proposing new VOC 

limits for solvent cleaning, the OTC 

convened a group of experts that 

suggested a more stringent model rule 

than what is provided in the CTG and 

the 2001 Model Rule. The OTC then 

developed the 2012 Model Rule for 

Solvent Degreasing (2012 Model Rule). 

The provisions set forth in the 2012 

Model Rule are more stringent than 

those currently included in the 

Delaware SIP and form the basis of the 

Delaware SIP revision we are proposing 

to approve in this rulemaking. This 

revision eliminates an existing 

exemption by adding provisions that 

apply to owners or operators of a 

solvent cleaning machine that uses any 

volume of solvent containing VOC. This 

revision also reduces the solvent VOC 

concentration from 100 percent to 25 

grams per liter of non-VOC solution for 

most applications. 

Certain areas of Delaware are 

designated as nonattainment for groundlevel ozone. Ground-level ozone is 

formed through the reaction of VOCs 

and other compounds in the air in the 

presence of sunlight. High levels of 

ground-level ozone can cause or worsen 

difficulty in breathing, asthma and other 

serious respiratory problems. In 

addition to improving public health and 

the environment, decreased emissions 

of VOCs, and therefore subsequently 

ground-level ozone, will contribute to 

the attainment of the ozone national 

ambient air quality standard (NAAQS). 

By removing an applicability 

exemption and decreasing the allowable 

solvent VOC concentration, the 2012 

Model Rule is expected to decrease 

emissions of VOCs. This reduction of 

VOC emissions from solvent cleaning 

operations will further reduce the 

formation of ground-ozone. Therefore, 

Delaware is amending their SIP to 

implement the updated 2012 Model 

Rule. 

II. Summary of SIP Revision and EPA 

Analysis 

This SIP revision, submitted by the 

State of Delaware on October 13, 2021, 

amends 7 DE Admin. Code 1124 section 

33.0, Solvent Cleaning and Drying. The 

amendments to section 33.1 

(Applicability) add provisions that 

apply to owners or operators of a 

solvent cleaning machine that uses any 

volume of solvent containing VOC. 

Therefore, the amendments eliminate 

the previous exemption for cold 

cleaning machines containing less than 

one liter of solvent and 5% by weight 

VOC. Section 33.1 also clarifies that it 

does not cover solvent cleaning 

machines that use the following 

hazardous air pollutants (HAPs): 

methylene chloride, perchloroethylene 

or 1,1,1-trichloroethane. Additionally, 


jspears on DSK121TN23PROD with PROPOSALS1