Emergency Application — National Rural Electric Cooperative, Applicant v. Environmental Protection Agency, et al.

Supreme Court briefJul 24, 2024

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No. _____

In the Supreme Court of the United States

N ATIONAL R URAL E LECTRIC C OOPERATIVE A SSOCIATION ,

Applicant,

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY and

MICHAEL REGAN, in his official capacity as Administrator of the United States

Environmental Protection Agency,

Respondents.

TO THE HONORABLE JOHN G. ROBERTS, JR.,

CHIEF JUSTICE OF THE UNITED STATES AND

CIRCUIT JUSTICE FOR THE UNITED STATES COURT OF APPEALS FOR THE

DISTRICT OF COLUMBIA CIRCUIT

APPLICATION FOR IMMEDIATE STAY OF FINAL AGENCY ACTION

PENDING APPELLATE REVIEW

Mithun Mansinghani

LEHOTSKY KELLER COHN LLP

629 W. Main St.

Oklahoma City, OK 73102

Joshua P. Morrow

LEHOTSKY KELLER COHN LLP

408 W. 11th St., 5th Floor

Austin, TX 78701

Scott A. Keller

Counsel of Record

Steven P. Lehotsky

Michael B. Schon

Jacob B. Richards

LEHOTSKY KELLER COHN LLP

200 Massachusetts Ave. NW, Ste. 700

Washington, DC 20001

(512) 693-8350

scott@lkcfirm.com

Counsel for the National Rural Electric

Cooperative Association

I DENTITY OF P ARTIES , C ORPORATE D ISCLOSURE S TATEMENT ,

AND R ELATED P ROCEEDINGS

Applicant is the National Rural Electric Cooperative Association (NRECA).

Pursuant to Rule 29.6, Applicant NRECA states that it represents nearly 900

consumer-owned, not-for-profit electric cooperatives, public power districts, and

public utility districts in the United States. NRECA’s mission is to promote, support,

and protect the community and business interests of electric cooperatives, to power

communities, and to empower members to improve the quality of life in their

communities. NRECA has no parent company, and no publicly held company owns

10% or more of NRECA’s stock.

Respondents are the United States Environmental Protection Agency (EPA) and

Michael Regan, in his official capacity as Administrator of the EPA.

The other parties to the consolidated proceedings below are:

Petitioners: State of West Virginia; State of Alabama; State of Alaska; State of

Arkansas; State of Florida; State of Georgia; State of Idaho; State of Indiana; State

of Iowa; State of Kansas; Commonwealth of Kentucky; State of Louisiana; State of

Mississippi; State of Missouri; State of Montana; State of Nebraska; State of New

Hampshire; State of North Dakota; State of Ohio; State of Oklahoma; State of South

Carolina; State of South Dakota; State of Tennessee; State of Texas; State of Utah;

Commonwealth of Virginia; State of Wyoming; America’s Power; Appalachian Region

Independent Power Producers Association; Edison Electric Institute (also an

Intervenor); Electric Generators for a Sensible Transition; Idaho Power Company;

International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers

and Helpers, AFL-CIO; International Brotherhood of Electrical Workers, AFL-CIO;

Midwest Ozone Group; Montana-Dakota Utilities Co.; NACCO Natural Resources

Corporation; National Mining Association; Oklahoma Gas and Electric Company;

Rainbow Energy Center, LLC; United Mine Workers of America, AFL-CIO;

Westmoreland

Mining

Holdings

LLC;

Westmoreland

Mining

LLC;

and

Westmoreland Rosebud Mining LLC.

Intervenors: State of New York; State of Arizona; State of Colorado; State of

Connecticut; State of Delaware; State of Hawaii; State of Illinois; State of Maine;

State of Maryland; Commonwealth of Massachusetts; State of Michigan; State of

Minnesota; State of New Jersey; State of New Mexico; State of North Carolina; State

of Oregon; Commonwealth of Pennsylvania; State of Rhode Island; State of Vermont;

State of Washington; State of Wisconsin; District of Columbia; City and County of

Denver; City of Boulder; City of Chicago; City of New York; California Air Resources

Board; American Lung Association; American Public Health Association; Clean Air

Council; Clean Wisconsin; Consolidated Edison, Inc.; Edison Electric Institute (also

a Petitioner); Louisiana Public Service Commission; Natural Resources Defense

Council; New York Power Authority; Pacific Gas and Electric Company; Power

Companies Climate Coalition; Sacramento Municipal Utility District; and Tennessee

Valley Public Power Association.

Amici Curiae: Chamber of Commerce of the United States of America;

Environmental Defense Fund; Professor Rachel Rothschild; and Sierra Club.

The related proceedings are:

West Virginia v. EPA, No. 24-1120 (D.C. Cir. July 19, 2024) (lead case) (order

denying motions for stay), consolidated with: Ohio v. EPA, No. 24-1121 (D.C. Cir. July

19, 2024); National Rural Electric Cooperative Association v. EPA, No. 24-1122 (D.C.

Cir. July 19, 2024); National Mining Association v. EPA, No. 24-1124 (D.C. Cir. July

19, 2024); Oklahoma Gas and Electric Company v. EPA, No. 24-1126 (D.C. Cir. July

19, 2024); Electric Generators for a Sensible Transition v. EPA, No. 24-1128 (D.C. Cir.

July 19, 2024); United Mine Workers of America v. EPA, No. 24-1142 (D.C. Cir. July

19, 2024); International Brotherhood of Electrical Workers v. EPA, No. 24-1143 (D.C.

Cir. July 19, 2024); International Brotherhood of Boilermakers v. EPA, No. 24-1144

(D.C. Cir. July 19, 2024); Midwest Ozone Group v. EPA, No. 24-1146 (D.C. Cir. July

19, 2024); Edison Electric Institute v. EPA, No. 24-1152 (D.C. Cir. July 19, 2024);

NACCO Natural Resources Corporation v. EPA, No. 24-1153 (D.C. Cir. July 19, 2024);

Idaho Power Company v. EPA, No. 24-1155 (D.C. Cir. July 19, 2024); Appalachian

Region Independent Power Producers Association v. EPA, No. 24-1222 (D.C. Cir. July

19, 2024); Rainbow Energy Center, LLC v. EPA, No. 24-1226 (D.C. Cir. July 19, 2024);

Montana-Dakota Utilities Co. v. EPA, No. 24-1227 (D.C. Cir. July 19, 2024); and

Westmoreland Mining Holdings LLC v. EPA, No. 24-1233 (D.C. Cir. July 19, 2024).

American Lung Association v. EPA, No. 19-1140 (D.C. Cir., June 25, 2024) (lead

case) (order holding cases in abeyance pending disposition of West Virginia v. EPA,

No. 24-1120 (D.C. Cir.)), consolidated with: Appalachian Mountain Club v. EPA, No.

19-1166 (D.C. Cir., June 25, 2024); State of New York v. EPA, No. 19-1165 (D.C. Cir.,

June 25, 2024); Chesapeake Bay Foundation, Inc v. EPA, No. 19-1173 (D.C. Cir., June

25, 2024); The North American Coal Corporation v. EPA, No. 19-1179 (D.C. Cir., June

25, 2024); Robinson Enterprises, Inc., v. EPA, No. 19-1175 (D.C. Cir., June 25, 2024);

iii

Westmoreland Mining Holdings LLC v. EPA, No. 19-1176 (D.C. Cir., June 25, 2024);

Biogenic CO2 Coalition v. EPA, No. 19-1185 (D.C. Cir., June 25, 2024); City and

County of Denver v. EPA, No. 19-1177 (D.C. Cir., June 25, 2024); Advanced Energy

Economy v. EPA, No. 19-1186 (D.C. Cir., June 25, 2024); American Clean Power

Association v. EPA, No. 19-1187 (D.C. Cir., June 25, 2024); Consolidated Edison, Inc.

v. EPA, No. 19-1188; and State of Nevada v. EPA, No. 19-1189 (D.C. Cir., June 25,

2024).

T ABLE OF C ONTENTS

Page

Identity of Parties, Corporate Disclosure Statement, and Related

Proceedings ................................................................................................................. i

Table of Authorities ...................................................................................................... vii

Glossary ........................................................................................................................... x

Introduction ..................................................................................................................... 1

Opinion Below ................................................................................................................. 6

Jurisdiction...................................................................................................................... 6

Statutory Provisions Involved ........................................................................................ 6

Statement ........................................................................................................................ 7

A. Statutory overview of Clean Air Act Section 111 .................................... 7

B. EPA’s 90% carbon-capture-and-sequestration (“CCS”) Rule .................. 8

Existing coal-fired units ..................................................................... 8

New gas-fired units .......................................................................... 10

C. Procedural history ................................................................................... 10

Reasons for Granting the Application ......................................................................... 10

If the D.C. Circuit upholds EPA’s 90% carbon-capture-andsequestration (CCS) Rule, there is a reasonable probability that

four Justices would vote to grant review and a fair prospect that a

majority would hold the Rule unlawful. ........................................................ 11

A. The Rule exceeds EPA’s Clean Air Act Section 111 authority. ............. 12

An annual carbon capture rate of 90% for an entire power

plant has not been “adequately demonstrated” anywhere. ............ 13

EPA’s best example—Boundary Dam—has never

demonstrated anything close to 90% annual carbon

capture from the entire unit. .................................................... 13

EPA’s other examples of existing power plants using

some form of carbon capture likewise have never

demonstrated 90% annual capture from an entire

unit. ............................................................................................ 16

The non-power-plant sources EPA cites have never

demonstrated 90% annual capture from an entire

unit. ............................................................................................ 18

The Act does not allow EPA to use forward-looking

guesswork to show that 90% capture has been

demonstrated. ............................................................................ 20

A “system” that combines 90% carbon capture, transport,

and storage has not been “adequately demonstrated”

anywhere. .......................................................................................... 23

The Rule’s emissions limits are not “achievable.” .......................... 24

The Rule’s alternative compliance options unlawfully

require generation-shifting. ............................................................. 29

B. The major-questions doctrine confirms that the Rule is

unlawful. .................................................................................................. 30

C. The Rule is arbitrary and capricious. ..................................................... 32

II. Applicant NRECA’s members will suffer substantial irreparable

harms absent a stay........................................................................................ 35

III. The equities and relative harms favor a stay. .............................................. 39

Conclusion ..................................................................................................................... 40

T ABLE OF A UTHORITIES

Page(s)

Cases

Ala. Ass’n of Realtors v. HHS,

594 U.S. 758 (2021) ........................................................................................... 35, 39

Baltimore Gas & Elec. Co. v. Nat. Res. Def. Council, Inc.,

462 U.S. 87 (1983) ............................................................................................. 17, 28

Carr v. United States,

560 U.S. 438 (2010) ..................................................................................... 12, 20, 30

Chamber of Com. v. EPA,

577 U.S. 1127 (2016) ..................................................................................... 6, 10, 12

Essex Chem. Corp. v. Ruckelshaus,

486 F.2d 427 (D.C. Cir. 1973) ................................................................................. 20

FCC v. Prometheus Radio Project,

592 U.S. 414 (2021) ................................................................................................. 33

Hollingsworth v. Perry,

558 U.S. 183 (2010) ................................................................................................. 11

King v. Burwell,

576 U.S. 473 (2015) ................................................................................................. 31

Labrador v. Poe,

144 S. Ct. 921 (2024) ............................................................................................... 39

Lignite Energy Council v. EPA,

198 F.3d 930 (D.C. Cir. 1999) ........................................................................... 20, 21

Michigan v. EPA,

576 U.S. 743 (2015) ........................................................................................... 34, 39

Nat’l Lime Ass’n v. EPA,

627 F.2d 416 (D.C. Cir. 1980) ..................................................................... 25, 26, 29

NFIB v. OSHA,

595 U.S. 109 (2022) ..................................................................................... 32, 35, 39

vii

Ohio v. EPA,

144 S. Ct. 2040 (2024) ........................................................... 4, 11, 32, 33, 35, 36, 39

Portland Cement Ass’n v. Ruckelshaus,

486 F.2d 375 (D.C. Cir. 1973) ..................................................................... 21, 25, 29

Sierra Club v. Costle,

657 F.2d 298 (D.C. Cir. 1981) ........................................................................... 20, 25

Util. Air Regul. Grp. v. EPA,

573 U.S. 302 (2014) ........................................................................................... 24, 30

West Virginia v. EPA,

597 U.S. 697 (2022) .................................................... 1, 4, 6-8, 10-12, 29, 30, 31, 32

Statutes

5 U.S.C. § 705 ............................................................................................................ 6, 10

5 U.S.C. § 706 ................................................................................................................ 32

28 U.S.C. § 651 ................................................................................................................ 6

28 U.S.C. § 1254 .............................................................................................................. 6

42 U.S.C. § 7411 ................................................................... 3, 7, 8, 12, 20, 23, 24, 29-31

42 U.S.C. § 7607 ............................................................................................................ 11

42 U.S.C. § 15962 .............................................................................................. 16, 17, 22

Other Authorities

79 Fed. Reg. 71,663 (Dec. 3, 2014) ............................................................................... 38

88 Fed. Reg. 33,240 (proposed May 23, 2023) ....................................................... 14, 26

89 Fed. Reg. 39,798 (May 9, 2024) ............................................................ 2-9, 13-35, 38

Angela C. Jones & Ashley J. Lawson, Cong. Rsch. Serv., Carbon Capture

and Sequestration (CCS) in the United States (Oct. 5, 2022),

https://perma.cc/L73B-JXAW .................................................................................. 32

EPA, Greenhouse Gas Mitigation Measures for Steam Generating Units

Technical Support Document (April 2024),

https://perma.cc/LEY3-VC2F ............................................................................ 25, 26

viii

EPA, In Perspective: the Supreme Court's Mercury and

Air Toxics Rule Decision (June 30, 2015),

https://perma.cc/D9NK-CNBB ................................................................................ 39

H.R. 2519, 117th Cong. (2021) ..................................................................................... 32

H.R. 4535, 114th Cong. (2016) ..................................................................................... 32

Ltr. from Gary McCutchen, EPA to Richard E. Grusnick Ala. Dep’t Env’t

Mgmt. (July 28, 1987),

https://perma.cc/3CJM-WL9E ................................................................................. 25

Nichola Groom, Problems plagued U.S. CO2 capture project before

shutdown: document, Reuters, Aug. 7, 2020,

https://perma.cc/LM4F-PND3 ................................................................................ 16

S. 4280, 117th Cong. (2022) .......................................................................................... 32

G LOSSARY

Act

Clean Air Act, 42 U.S.C. §§ 7401 to 7671q

CCS

Carbon Capture and Sequestration (or Storage)

CO2

Carbon Dioxide

EPA (or agency)

U.S. Environmental Protection Agency

EPA Tech. Supp.

EPA, Greenhouse Gas Mitigation Measures for Steam

Generating Units Technical Support Document, (April

2024), https://perma.cc/LEY3-VC2F

NRECA

National Rural Electric Cooperative Association

Rule

New Source Performance Standards for Greenhouse

Gas Emissions From New, Modified, and

Reconstructed Fossil Fuel-Fired Electric Generating

Units; Emission Guidelines for Greenhouse Gas

Emissions From Existing Fossil Fuel-Fired Electric

Generating Units; and Repeal of the Affordable Clean

Energy Rule, 89 Fed. Reg. 39,798 (May 9, 2024)

Unit

Electric Generating Unit

T O THE H ONORABLE J OHN G. R OBERTS , J R .,

C HIEF J USTICE OF THE U NITED S TATES AND

C IRCUIT J USTICE FOR THE U NITED S TATES C OURT OF A PPEALS FOR THE

D ISTRICT OF C OLUMBIA C IRCUIT :

The National Rural Electric Cooperative Association (NRECA) respectfully

requests an immediate stay of the United States Environmental Protection Agency’s

(EPA) final rule entitled “New Source Performance Standards for Greenhouse Gas

Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric

Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing

Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean

Energy Rule.” 89 Fed. Reg. 39,798 (May 9, 2024) (the Rule).

I NTRODUCTION

EPA is once again trying to transform the power sector by forcing a shift in

electricity generation to its favored sources. This Court rejected that ploy in West

Virginia v. EPA, because Congress has not authorized EPA to “decid[e] how

Americans will get their energy.” 597 U.S. 697, 729 (2022). EPA’s new plan is just as

bad, presenting covered power plants with a Hobson’s choice. They must implement

an emissions-reduction system that has not been demonstrated anywhere (an annual

90% rate of carbon-capture-and-sequestration, also known as “CCS,” for each electricgenerating unit). Or they must shift electricity generation by shuttering coal units

and curtailing generation at new gas units. EPA’s chosen “system” of an annual 90%

CCS rate for each covered unit, therefore, far exceeds its authority to impose a system

of emission reduction that “has been adequately demonstrated” with emission

limitations that are “achievable.” 42 U.S.C. § 7411(a)(1).

NRECA and its members know that better than anyone. They are at the forefront

of exploring carbon capture at a significant scale, and they hope this emerging

technology will someday be deployable. See App.446-64a (McLennan ¶¶21-52);

App.351a (McCollam ¶18). Indeed, EPA relies on two NRECA members’ projects in

this Rule: Minnkota Power Cooperative’s (“Minnkota”) “Project Tundra” and Basin

Electric Power Cooperative’s (“Basin”) “Dry Fork” project. E.g., 89 Fed. Reg. at 39,814;

id. at 39,850; Resp. Opp. to Motions to Stay at 41, 43, 47, 50 (D.C. Cir. No. 24-1120,

June 11, 2024).

But each project is still just in the planning phase, neither project would comply

with this Rule, and both projects might not be completed if this Rule takes effect.

App.771-73a (Minnkota Comments 16-18); App.687a, App.689a (Basin Comments 17,

19); App.351-52a (McCollam ¶19); App.437-38a (McLennan ¶6). Project Tundra,

which is still in the pre-construction planning phase, is the Nation’s leading CCS

project. App.280a (NRECA Comments 7); App.446a (McLennan ¶21). If it is built,

Project Tundra would “be the largest [CO2] capture system in the world.” App.768a

(Minnkota Comments 13). But even it would not comply with this Rule. App.757a,

App.771a (Minnkota Comments 2, 16). Consequently, the Rule’s unachievable

requirements would force Minnkota to either abandon nine years of planning, or else

design a new capture system from scratch. App.766-68a (Minnkota Comments 1113). Dry Fork is also in the planning phase, and it would not comply with the Rule

either. App.689a (Basin Comments 19); App.351-52a (McCollam ¶19). Basin would

need to spend $1.5 billion to attempt to demonstrate only 70% capture at just one

unit. App.689a (Basin Comments 19). Both projects confirm what NRECA repeatedly

told the EPA in comments and the court below: (1) no entire power plant has ever

captured (2) anything near 90% of (3) its annual carbon-dioxide (“CO2”) emissions.

EPA’s brief below could not point to a single example.

EPA’s imposition of this 90% CCS “system” thus violates key limits Congress set

in Section 111 of the Clean Air Act (Act). The Rule’s “system of emission reduction”

has not “been adequately demonstrated” anywhere, and the Rule’s emissions caps

based on that system are not “achievable.” 42 U.S.C. § 7411(a)(1). The “system” EPA’s

Rule selects is “90 percent CCS”: capturing, transporting, and storing 90% of the

annual CO2 emissions from each entire unit covered by the Rule. 89 Fed. Reg. 39,80102. But the Rule does not identify a single power plant that has ever done this. On

the contrary, there have been only a few experimental efforts to use any type of CCS

at power plants. Almost all these experimental efforts have captured CO2 from just a

subset—that is, a “slipstream”—of a unit’s total emissions. E.g., Id. at 39,848-52. And

they suffered constant breakdowns along the way. Id.

Even if the technology for achieving a 90% annual capture rate for all of a unit’s

CO2 emissions became feasible, the Rule’s CCS “system” further requires that the

captured CO2 be transported and stored. But CO2 transport pipelines and storage

sites are still missing almost everywhere. Project Tundra, for example, is a possibility

only because it happens to be uniquely located one-quarter mile from a permitted

sequestration site, requiring only a small, mostly on-site, pipeline. App.769a

(Minnkota Comments 14); App.463-64a (McLennan ¶51). Few plants enjoy such

luxuries. So EPA’s emissions limitations are not “achievable.”

With no way to comply with the 90% CCS system, the Rule requires operators to

shift electricity generation. Existing coal units that cannot reach 90% CCS have two

options: commit to shut down by 2039 and convert the unit to burn at least 40%

natural gas until then, or shut down by 2032. 89 Fed. Reg. at 39,841. New gas units

that cannot reach 90% CCS must curtail their electricity generation to no more “than

40 percent of their potential electric output.” 89 Fed. Reg. at 39,917 tbl.3 n.1.

Meanwhile, electricity must come from somewhere. The mandated shutdowns and

curtailments thus require operators to shift electricity generation to other sources to

meet demand. Yet this Court just held that EPA cannot “force a nationwide transition

away from the use of [fossil fuels] to generate electricity.” West Virginia, 597 U.S. at

735. The right mix of electricity generation is a major question of “economic and

political significance” for Congress—not EPA—to decide. Id. at 730 (citation omitted).

Worse yet, EPA’s Rule will impose enormous irreparable injuries. Forced

shutdowns will slash electric reliability across the country and impose other

enormous, “nonrecoverable” compliance costs. Ohio v. EPA, 144 S. Ct. 2040, 2053

(2024) (cleaned up). Multiple NRECA members face costs of $10 billion or more each.

E.g., App.346a (McCollam ¶11); App.409a (Purvis ¶38). Part of that is replacement

power to offset the electricity supply that the Rule eliminates. Buying new power

from an already constrained market is enormously expensive. E.g., App.497-98a

(Tudor ¶¶23-24). So is building new units, App.527-28a (Hasten ¶31), or buying new

equipment to retrofit existing units, App.352a (McCollam ¶20) (estimating retrofits

would cost “more than 150% of what it cost to construct the [unit] in the first place

barely a decade ago”). Premature shutdowns will strand hundreds of millions in

assets. E.g., App.428-29a (Purvis ¶60); App.479-80a (McLennan ¶82).

The Rule’s enormous costs will fall disproportionately on those least able to

shoulder them. NRECA member cooperatives own over 75 of the coal-fired units

affected by this Rule. See 89 Fed. Reg. at 39,876; App.329a (Matheson ¶33). These

not-for-profit cooperatives serve mostly rural areas, where low populations and

incomes have not attracted for-profit power companies. That includes 92% of the

persistent-poverty counties in the United States, with average (mean) household

incomes 12% below the national average. App.318a (Matheson ¶10). Under EPA’s

Rule, NRECA members must spend billions to experiment on technology that has

never been demonstrated, or shutdown and build gas plants with constrained

capacity. E.g., App.346a (McCollam ¶11); App.412a (Purvis ¶43); App.479-80a

(McLennan ¶82); App.488-89a (Tudor ¶8); App.527-28a (Hasten ¶31); App.553-54a

(Grooms ¶28). Compared to other covered entities, the Rule’s costs for NRECA

member cooperatives will be borne across a base of fewer consumers and by families

that spend a higher percentage of their limited resources on electricity. E.g., App.31718a (Matheson ¶9); App.334-37a (Purvis ¶¶40-42).

All these harms start immediately. The Rule itself “assumes” that work toward

complying with this Rule will begin in “June 2024.” 89 Fed. Reg. at 39,874, 39,893.

For NRECA members who cannot even attempt using CCS—which is all of them

except Minnkota (Project Tundra) and Basin (Dry Fork)—the Rule requires imminent

retirement commitments. Id. at 39,997. NRECA member cooperatives will also need

to secure replacement power for the units that the Rule shuts down or curtails. That

new generation cannot be conjured overnight, and it requires huge new investments.

See App.595a (Porath ¶24). “[D]esign, engineering, consulting, site studies, and

numerous other pre-construction activities” can easily exceed tens of millions per

unit. App.447a (McLennan ¶24). Even early-stage “[e]ngineering costs typically

represent approximately five percent of project costs.” App.353a (McCollam ¶21). The

upshot is hundreds of millions in imminent spending.

There is no meaningful difference between substituting or prioritizing renewable

units (invalidated by West Virginia) and shutting down or curtailing production from

fossil-fuel units (required by this Rule). Both schemes require generation-shifting,

which exceeds EPA’s authority. West Virginia, 597 U.S. at 735. Applicant therefore

respectfully requests an immediate stay of EPA’s unlawful Rule preserving the status

quo pending judicial review—just as this Court did in the West Virginia litigation.

See Chamber of Com. v. EPA, 577 U.S. 1127 (2016) (mem.).

O PINION B ELOW

The D.C. Circuit’s order denying NRECA’s motion for a stay pending judicial

review is reproduced at App.270a. EPA’s final rule is published at 89 Fed. Reg. 39,798

(May 9, 2024) and reprinted at App.2a.

J URISDICTION

This Court has jurisdiction under 28 U.S.C. § 1254(1) and has authority to grant

relief under the Administrative Procedure Act, 5 U.S.C. § 705; the All Writs Act, 28

U.S.C § 1651; and Supreme Court Rule 23.

S TATUTORY P ROVISIONS I NVOLVED

“The term ‘standard of performance’ means a standard for emissions of air

pollutants which reflects the degree of emission limitation achievable through the

application of the best system of emission reduction which (taking into account the

cost of achieving such reduction and any nonair quality health and environmental

impact and energy requirements) the Administrator [of the EPA] determines has

been adequately demonstrated.” 42 U.S.C. § 7411(a)(1).

S TATEMENT

A. Statutory overview of Clean Air Act Section 111

Section 111 of the Act authorizes EPA to set “standards of performance” for new

stationary sources of certain air pollutants, and to establish guidelines that States

then use to set standards of performance for existing sources. 42 U.S.C. § 7411(b), (d).

Both types of “emissions limits under Section 111” aim to “reduce pollution by causing

the regulated source to operate more cleanly.” West Virginia, 597 U.S. at 725.

For new sources, EPA sets the standards itself. 42 U.S.C. § 7411(b). The agency

begins by identifying the “best system of emission reduction” (accounting for things

like “cost” and “energy requirements”) that “has been adequately demonstrated.” Id.

§ 7411(a)(1). EPA then quantifies the amount of emissions limitations “achievable”

by all sources in the category using that system. Id. Next, EPA translates that

amount into an “emissions cap” for individual units. West Virginia, 597 U.S. at 709.

For existing sources, EPA issues emissions guidelines for States to use in setting

their own standards of performance. See 42 U.S.C. § 7411(d)(1). To do this, EPA again

identifies a “system” that has been “adequately demonstrated,” and quantifies the

amount of limitation “achievable” using that system. Id. § 7411(a)(1). States then

translate that amount into a standard of performance using State “plan[s].” Id.

§ 7411(d)(1). But States can also consider other factors, including “the remaining

useful life” of an existing source. Id. West Virginia held that Section 111(d) gives EPA

no authority to cap CO2 “emissions at a level that will force a nationwide transition

away from the use of coal to generate electricity.” 597 U.S. at 735. EPA also has no

authority to “direct existing sources to effectively cease to exist.” Id. at 728 n.3.

Because a standard of performance must reflect the “best system of emission

reduction” that “has been adequately demonstrated” for the covered sources, 42 U.S.C

§ 7411(a)(1), Section 111 requires at a minimum that EPA “make sure the best system

has a proven track record,” West Virginia, 597 U.S. at 759 (Kagan, J., dissenting).

And the emissions limitation based on that system must be “achievable” by covered

sources across the Nation. See 42 U.S.C. § 7411(a)(1).

B. EPA’s 90% carbon-capture-and-sequestration (“CCS”) Rule

The Rule establishes CO2 emissions guidelines for three subsets of existing coalfired electric-generating units, under Section 111(d). 89 Fed. Reg. at 39,840-41. The

Rule also sets CO2 standards of performance for three subcategories of new gas-fired

combustion-turbine units, under Section 111(b). Id. at 39,902. These subcategories

are all based on binding commitments to implement the equivalent of an annual 90%

CCS system for every unit, or else either shut down (for existing coal units) or

substantially curtail electric output (for new gas units). Id. at 39,805, 39,838, 39,841.

Existing coal-fired units

The Rule divides existing coal-fired units into three subsets: two are

“subcategories” and one is an “applicability exemption.” Id. at 39,805.

The first (and default) subcategory is for “long-term” units. Id. at 39,838. All coal

units that “intend to operate past January 1, 2039” are part of this subcategory. Id.

EPA says that the best system for this subcategory is CCS that captures 90% of the

annual CO2 emissions from the entire unit. Id. at 39,845. This system requires the

design, engineering, and installation of bespoke CO2 capture technology. Id. at

39,846. The captured CO2 must then be transported (usually via pipeline) to a site

that has a permit to permanently store it underground. Id. EPA “assumes” that

“work” toward “each component of CCS” will begin in “June 2024.” Id. at 39,874. And

operators must complete that work before January 1, 2032. Id. at 39,801.

The second subcategory is for “medium-term” units. Id. at 39,841. All units that

commit “to permanently cease operation after December 31, 2031, [but] before

January 1, 2039” are part of this subcategory. Id. at 39,890. EPA says that the best

system for this subcategory is “40 percent natural gas co-firing.” Id. That means

transforming a coal unit into one that combusts both coal and natural gas. See id.

Just “[a]s in the timeline for CCS,” EPA “assumes” that “work” toward co-firing will

begin in June 2024. Id. at 39,893. Medium-term units must complete that work before

January 1, 2030, and then they must retire nine years later. Id. at 39,845.

Third, the Rule establishes an “applicability exemption” for units that commit “to

permanently cease operation before January 1, 2032.” Id. at 39,841. These units “are

not regulated” by any other requirements of the Rule. Id. at 39,843.

The Rule imposes a multistep process to opt out of the default, “long-term” first

subcategory. The choice is not effective unless it is “included in a State plan.” Id. at

39,958. States must submit their plans to EPA by May 11, 2026. Id. at 40,056. Thus,

an operator must choose its subcategory in time for the State to include that choice

in the plan that it submits to EPA. Once EPA approves a plan, each subcategory’s

prerequisites become federally enforceable against the unit. Id. If any of that goes

wrong, the unit stays in the default, long-term subcategory (90% CCS by 2032). See

id. at 40,049.

New gas-fired units

For new and modified gas-fired combustion turbines, the Rule creates three

subcategories. These subcategories are defined by a unit’s “electric sales (i.e.,

utilization) relative to the [unit’s] potential electric output.” Id. at 39,908.

“Base load” units, those that sell more than 40% of their potential output, must

comply with a “multi-phase standard of performance.” Id. at 39,923. Phase I is “based

on the performance of a highly efficient” unit and has “an immediate compliance

date.” Id. at 39,903. Phase II is based on an annual 90% CCS rate and has “a

compliance date of January 1, 2032.” Id. “Intermediate load” units, those that commit

to sell no more than 20-40% of their potential output, must comply with a standard

based on “high-efficiency simple cycle turbine[s].” Id. at 39,918. “Low load” units,

those that commit to sell “20 percent or less of their potential electric output,” must

comply with a standard of performance based on “lower-emitting fuels.” Id. at 39,917

& tbl.3 n.1.

C. Procedural history

Applicant filed its Petition for Review on May 9, 2024. That same day, Applicant

asked EPA to stay the Rule pending judicial review. EPA has not responded to that

request. Applicant filed its motion for a stay pending judicial review with the D.C.

Circuit on May 13. The D.C Circuit denied Applicant’s stay motion on July 19, 2024.

R EASONS FOR G RANTING THE A PPLICATION

This Court should stay EPA’s latest attempt at shifting electricity generation,

just as it did in the litigation leading up to West Virginia v. EPA. See Chamber of

Com., 577 U.S. at 1127. Under 5 U.S.C. § 705, this Court “may . . . postpone the

effective date of any agency action.” “In deciding whether to issue a stay,” this Court

asks “(1) whether the applicant is likely to succeed on the merits, (2) whether it will

suffer irreparable injury without a stay, (3) whether the stay will substantially injure

the other parties interested in the proceedings, and (4) where the public interest lies.”

Ohio v. EPA, 144 S. Ct. at 2052. All four factors support a stay of EPA’s unlawful rule.

If the D.C. Circuit upholds EPA’s 90% carbon-capture-and-sequestration

(CCS) Rule, there is a reasonable probability that four Justices would

vote to grant review and a fair prospect that a majority would hold the

Rule unlawful.

EPA’s 90% CCS Rule would remake the Nation’s energy grid. It requires

Applicant’s not-for-profit members to spend billions trying to achieve carbon-captureand-sequestration at a level never demonstrated before—or else either shut down or

curtail output. Even if these high annual capture rates were possible, the pipelines

and storage sites needed to pull this off do not exist. So this Rule is a thinly veiled

attempt at forcing the electricity-generation industry to produce power from EPA’s

preferred sources. The Rule is thus unlawful under the plain text of Clean Air Act

Section 111, as confirmed by West Virginia v. EPA and the major-questions doctrine.

NRECA satisfies the likelihood-of-success prong of the stay test. There is “a

reasonable probability that four Justices will consider the issue sufficiently

meritorious to grant certiorari,” plus “a fair prospect that a majority of the Court

w[ould] vote to reverse [a] judgment below [upholding the Rule].” Hollingsworth v.

Perry, 558 U.S. 183, 190 (2010) (per curiam). No circuit split can emerge, because the

D.C. Circuit’s jurisdiction is exclusive. 42 U.S.C. § 7607(b)(1). This Court often

reviews the D.C. Circuit’s decisions about EPA’s use of the Clean Air Act to attempt

major transformations of the national economy. E.g., Chamber of Com., 577 U.S. at

1127 (staying the Clean Power Plan); West Virginia, 597 U.S. at 697.

A. The Rule exceeds EPA’s Clean Air Act Section 111 authority.

Under the Act’s plain text, the Rule exceeds EPA’s Section 111 authority. The

Rule creates a mandate for existing coal plants that do not commit to retire, and for

new gas plants that produce 40% or more of their capacity. They must reduce their

emissions based on a 90% CCS “system” integrating CO2 capture, transport, and

storage. The Rule is lawful only if this tripartite “system” “has been adequately

demonstrated.” 42 U.S.C. § 7411(a)(1). The Act’s statutory text—“has been

adequately demonstrated”—uses the present perfect tense. Id. And “Congress use[s]

the present perfect tense to denote an act that has been completed.” Carr v. United

States, 560 U.S. 438, 448 (2010) (emphasis added; cleaned up). A system “has been

adequately demonstrated,” 42 U.S.C. § 7411(a)(1), only if its actual use “has been

completed” in the past, Carr, 560 U.S. at 448.

EPA has not identified any power plant that has ever demonstrated 90% annual

capture from an entire unit. Yet EPA interprets “has been adequately demonstrated”

to reach such a never-before-used system. Even if 90% capture had been

demonstrated, 90% CCS depends on the additional ability to transport CO2 to a

permitted storage site. The pipelines for transport and the storage sites for

sequestration are severely lacking. That is another reason that the Rule’s integrated

90% CCS system has not “been adequately demonstrated” and its emissions levels

are not “achievable.” Id. Meanwhile, EPA’s alternative compliance paths require

generation-shifting, rendering the Rule invalid under West Virginia, 597 U.S. at 735.

An annual carbon capture rate of 90% for an entire power plant

has not been “adequately demonstrated” anywhere.

This Rule does far more than require power plants to use carbon capture in some

generalized sense. The capture element of EPA’s selected emission-reduction

“system” requires power plants to capture (1) 90% of CO2 emissions (2) from an entire

unit (3) for an entire year. See 89 Fed. Reg. at 39,801 (existing coal-fired units); id. at

39,802 (new gas-fired units). The Rule cites no example of any power plant that has

ever done this. Instead, EPA points to power plants that have implemented lower

levels of capture, non-power-plant “industrial” sources that have implemented lower

levels of capture using entirely different processes, speculative sales pitches from

vendors, and future demonstration projects that are planned but have not been built.

From this, EPA makes the legal conclusion its 90% CCS system “has been adequately

demonstrated.” 89 Fed. Reg. at 39,845. This violates the Act’s plain text, so the entire

Rule is unlawful.

EPA’s

best

example—Boundary

Dam—has

never

demonstrated anything close to 90% annual carbon capture

from the entire unit.

EPA’s leading purported example of a 90% CCS system is Boundary Dam, a

Canadian project that began operating in 2015. See 89 Fed. Reg. at 39,847. Boundary

Dam has never achieved 90% capture from an entire unit for an entire year. It can

capture CO2 only from a partial “slipstream” of the unit’s emissions, and it has

suffered constant breakdowns and disruptions. Rather than supporting the Rule,

Boundary Dam shows just how far off 90% CCS still is. This is exactly why Congress

required a system to be adequately demonstrated before EPA mandates its use.

First, Boundary Dam has never demonstrated EPA’s 90% capture system. EPA’s

Proposed Rule said it had.1 But the Canadian company operating Boundary Dam

commented to set the record straight. App.784a (SaskPower Comments 1). It

unequivocally told EPA: “SaskPower’s CCS facility is not capturing 90 per cent of

emissions from Boundary Dam.” Id. (emphasis added). During a mere 72-hour test in

2015, Boundary Dam once captured “89.7 percent” of total emissions. 89 Fed. Reg. at

39,848. Since then, Boundary Dam has suffered constant “technical issues,” requiring

“consistent[] . . . modifications . . . to stabilize operations” and “improve reliability.”

App.784a (SaskPower Comments 1). So, “[t]o ensure a higher level of overall

equipment reliability and process efficiency,” the plant “targets” a capture rate of “65

to 70 per cent.” Id.

Second, Boundary Dam has not demonstrated carbon capture from an entire unit.

Boundary Dam captures only from what the industry calls a “slipstream” system. 89

Fed. Reg. at 39,848. Slipstream systems siphon and process a partial, fixed, constant

stream of a unit’s total emissions. See, e.g., App.849a (EERC Comments 5). The rest

“is released to the atmosphere.” App.784a (SaskPower Comments 1). Slipstreams

function reliably because gas pressures and volumes are static and controllable

within that partial stream. See 89 Fed. Reg. at 39,853 n.358 (“[P]rocess value[s], such

New Source Performance Standards for Greenhouse Gas Emissions From New,

Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission

Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric

Generating Units; and Repeal of the Affordable Clean Energy Rule, 88 Fed. Reg. at

33,240, 33,291 (proposed May 23, 2023) (Proposed Rule).

as flowrate, throughput or capacity . . . are designed to operate within specific ranges

. . . .”). In stark contrast, a full-stream system would need to contend with dynamic

pressure and volumes, shifting as the unit responds to electricity demand. See

App.796a (Cichanowicz Comments 3 & n.7). These two systems are categorically

different. See id.

Boundary Dam captures from only a slipstream because the full stream of

emissions “cannot be processed through the CCS facility.” App.784a (SaskPower

Comments 1 (emphasis added)). That is especially notable because Boundary Dam

was “designed” to operate as a full-stream capture system. 89 Fed. Reg. at 39,848.

But the full-stream design did not reliably work, even after almost a decade.

App.784a (SaskPower Comments 1). That failure shows the folly in EPA’s near-total

reliance on projects that are merely “proposed,” 89 Fed. Reg. at 39,927; “designed,”

id. at 39,848; “planned,” id. at 39,851; or “targeted for completion,” id.

Third, Boundary Dam has not demonstrated capture for an entire year. EPA

claims Boundary Dam “achiev[ed] capture rates of 83 percent when the capture plant

is online.” 89 Fed. Reg. at 39,848 (emphasis added). That qualifier obscures this

project’s persistent breakdowns. App.284a (NRECA Comments 11). From early 2021

to early 2023, Boundary Dam’s CCS system was “online” only about 65% of the time.

Id. at 19. EPA concedes this system was continually “affected by technical issues.” 89

Fed. Reg. at 39,848. SaskPower acknowledged the same. App.784a (SaskPower

Comments 1).

So the system that Boundary Dam’s operator says it cannot use, id., is the very

same system EPA says has “been adequately demonstrated” by Boundary Dam, 89

Fed. Reg. at 39,847. Boundary Dam has not demonstrated anything close to the 90%

CCS system required by the Rule—and that is the very best example EPA can cite.

EPA’s other examples of existing power plants using some

form of carbon capture likewise have never demonstrated

90% annual capture from an entire unit.

EPA’s Rule focuses on eight other power plants that have implemented limited

degrees of carbon capture. See 89 Fed. Reg. at 39,848-51. These are even further afield

than Boundary Dam, many have shuttered, and none of them ever demonstrated

EPA’s 90% CCS system.

“Petra Nova” is a slipstream system at a coal-fired power plant that operated for

three years. See 89 Fed. Reg. at 39,849. It “was designed to capture 33% of the carbon

emissions from one of four units” at that plant.2 It fell short of even that lower capture

rate. App.850a (EERC Comments 6). Technical problems kept it “offline for more than

a third of the time that it was operational before it was shut down in 2020 . . . [and]

sold for a fraction of its initial investment.” App.284a (NRECA Comments 11). Plus,

a separate “auxiliary” unit had to power the capture equipment. See 89 Fed. Reg. at

39,850. EPA ignores that separate unit’s emissions in discussing Petra Nova’s

capture rates. See id. Regardless, Petra Nova was funded by the Energy Policy Act of

2005. Id. at 39,852 n.334. That statute precludes EPA from relying on projects

receiving its funding to establish that a system is demonstrated under Section 111.

Nichola Groom, Problems plagued U.S. CO2 capture project before shutdown:

document, Reuters, Aug. 7, 2020, https://perma.cc/LM4F-PND3 (emphasis added); see

App.850a (EERC Comments 6) (citing this article and noting that Petra Nova “missed

its carbon capture targets by ∼17%”).

42 U.S.C. § 15962(i)(1); see infra p.22. EPA acknowledges this, begrudgingly. See 89

Fed. Reg. at 39,878 & n.613.

“Barry” is a slipstream that captured “three percent of . . . total CO2 emissions”

from a coal-fired unit in Alabama. App.735a (Buckeye Inst. Comments 10). EPA calls

this “a capture rate of 90 percent” from a “25 MWe” unit. 89 Fed. Reg. at 39,850. This

rosy view ignores that Barry was just a slipstream from a larger “770 MW” unit.

App.735a (Buckeye Inst. Comments 10). Barry also received funding under the

Energy Policy Act of 2005, see 89 Fed. Reg. at 39,849, again precluding EPA from

relying on it for the Rule, 42 U.S.C. § 15962(i)(1).

“Argus” is a power plant in California. See 89 Fed. Reg. at 39,846-47.

Commenters estimate that its capture “rate approximates to 18%.” App.849a (EERC

Comments 5 (emphasis added)); see App.796a (Cichanowicz Comments 3) (estimating

the rate equates to “33% removal”). EPA attempts to mask this low percentage rate

by describing Argus’s capture only in terms of “metric tons of CO2 per year.” 89 Fed.

Reg. at 39,846.

“Warrior Run,” another slipstream at a coal-fired unit, captures “approximately

10 percent of the plant’s CO2 emissions.” Id. at 39,849 (emphasis added).

“Shady Point” is a coal-fired power plant that “captured CO2 from an

approximate 5 percent slipstream” from 2001 through 2019. Id. (emphasis added).

“Bellingham,” EPA claims, is “[t]he most prominent example of the use of carbon

capture technology” at a gas unit. Id. at 39,926. But it closed in 2005. Id. It captured

“85-95 percent of the CO2 that would have otherwise been emitted from . . . a 40 MW

slip stream.” Id. That is only about 10% capture from the entire “386 MW” unit. Id.

“Mongstad” is a slipstream “demonstration facilit[y],” id. at 39,852, that can

“treat a 12 MWe flue gas stream from a natural gas . . . power station” in Norway, id.

at 39,927. While Mongstad has “achiev[ed] capture rates of over 98 percent” from this

slipstream, id., that equates to less than a 5% capture rate for the entire unit.3

“La Porte” is a “test facility” in Texas that its owner describes as “one-of-a-kind.”

App.864a, App.867a (NET Power Comments 3, 6). It uses a proprietary process for

producing electricity that combusts a fuel with purified oxygen. See App.864-66a

(NET Power Comments 3-5). This process “is not currently applicable to coal-fired

steam generating utility boilers.” 89 Fed. Reg. at 39,925. Therefore, it cannot show

that 90% CCS is demonstrated for existing coal-fired units. Regardless, this single

“test facility” operated on average only about 10 days per year since 2018. See id. at

39,927. That is far short of 90% CCS annually, so La Porte’s proprietary process has

not demonstrated that system for new gas-fired units either.

These eight projects (plus Boundary Dam) are the only examples that EPA

highlights in which CCS has ever been used at a power plant anywhere. None of them

ever achieved anything close to 90% annual capture for an entire unit.

The non-power-plant sources EPA cites have never

demonstrated 90% annual capture from an entire unit.

EPA cannot identify a single power plant that has demonstrated its 90% CCS

system. So EPA points to “industrial applications” of CO2 capture—that is, CCS

3 The Proposed Rule’s preamble did not cite this facility. But the Mongstad Power

Plant produces 280 MW in electricity and 350 MW in heat, of which the

“demonstration facilit[y]” captures only a “12MWe” slipstream. 89 Fed. Reg. 39,852;

see id. at 39,927.

applications at sources other than power plants. 89 Fed. Reg. at 39,846. But the Rule’s

system requires power plants to capture the CO2 that they generate by burning fuel.

See id. By contrast, the “industrial applications” EPA names remove CO2 from a fuel

before combustion. That is markedly distinct from the Rule’s 90% CCS “system.”

Regardless, EPA does not identify the CO2 capture rates for these industrial

applications, whether they captured from an entire unit (or equivalent), or whether

they did so annually.

“Great Plains Synfuels” is owned and operated by NRECA’s member Basin. 89

Fed. Reg. at 39,864 & n.472. It is the “only” project of its kind and has reduced “CO2

emissions . . . by 45%” at the Great Plains plant. App.846a (EERC Comments 2). But

the project uses “precombustion CO2 capture,” which “is not considered a leading

technology for . . . electrical generation.” Id. (emphasis added). Indeed, in defining

“CCS,” the Rule itself says “[t]his technology [i.e., CCS] is referred to as ‘postcombustion capture.’’’ 89 Fed. Reg. at 39,846 (emphasis added). Thus, a precombustion system cannot show that the post-combustion capture that the Rule is

premised on has been demonstrated. See id. at 39,848 (similar).

“Quest” is a Canadian chemical plant capturing CO2 from a “methane reforming

process” that “does not reflect combustion products.” App.796a (Cichanowicz

Comments 3). Further, at Quest, “CO2 content is elevated compared to utility

application.” Id. Because the CO2 is “elevated,” it is much easier to capture CO2 at

Quest than to do the same at a power plant. Id. Even so, Quest has been able to

achieve only an annual average “capture rate of 79.4%.” App.850a (EERC Comments

6); see 89 Fed. Reg. at 39,847 (“approximately 80 percent”).

“Shute Creek” is another pre-combustion system. Id. at 39,847. It “uses a solventbased process to remove CO2 from natural gas” so that the gas can then be marketed

and sold for electricity-generation and other applications. Id.

Despite those crucial differences, these and other so-called “industrial

applications” account for 14 of what the Rule repeatedly refers to as “at least 15

operating CCS projects in the U.S.” E.g., id. at 39,813, 38,847. (The fifteenth project

is the Petra Nova power plant, discussed above at p.16.). But “operating CCS” in nonpower-plant industrial applications is nothing like the 90% CCS system EPA’s Rule

mandates for covered power plants. See id. at 39,847. In any event, the Rule does not

identify the capture rates for these industrial applications. Thus, these non-powerplant sources have not “adequately demonstrated” 90% capture for power plants.

The Act does not allow EPA to use forward-looking

guesswork to show that 90% capture has been demonstrated.

With no examples of 90% capture having “been” demonstrated, EPA rewrites the

Act and engages in speculative “extrapolation.” 89 Fed. Reg. at 39,831. Under EPA’s

interpretation of its statutory delegation, “an adequately demonstrated standard of

performance may reflect the EPA’s reasonable projection of what that particular

system may be expected to achieve going forward.” Id. Such “projection,” id.,

contradicts the Act’s directive for EPA to identify a system that “has been adequately

demonstrated,” 42 U.S.C. § 7411(a)(1); see Carr, 560 U.S. at 448.

Contrary to the Act’s plain text, the D.C. Circuit sometimes has allowed EPA to

make minor extrapolations in setting standards for new sources (not existing

sources). See, e.g., Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999);

Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981); Essex Chem. Corp. v.

Ruckelshaus, 486 F.2d 427, 438 (D.C. Cir. 1973). But even under the D.C. Circuit’s

atextual caselaw, the Rule’s predictions are prohibited “speculation,” not incremental

“extrapolation.” Lignite, 198 F.3d at 934. EPA does not identify even one power plant

that has ever achieved anything near 90% CCS annually for an entire unit.

The Rule repeatedly cites things that have not happened, like vendor statements

about what an engineering firm or manufacturer thinks it could do in the future. 89

Fed. Reg. at 39,851. EPA also relies heavily on “planned” or “designed” projects that

may (or may not) be built in the future. E.g., id. at 39,848-50. And the Rule constantly

extrapolates from CCS technology in general to the specific 90% CCS system the Rule

would require. E.g., id. at 39,846-55. That guesswork is all “crystal ball” thinking,

which even the D.C. Circuit’s cases prohibit. See, e.g., Portland Cement Ass’n v.

Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973).

EPA’s prominent reliance on NRECA members’ planned projects makes this

abundantly clear. The Rule devotes an entire subsection of the preamble to Project

Tundra, which is being developed by NRECA member Minnkota. See 89 Fed. Reg. at

39,850-51. If it is built, Project Tundra would “be the largest [CO2] capture system in

the world.” App.768a (Minnkota Comments 13). But even with substantial state and

federal funding, and “exceptional geology” yielding a storage site just a quarter-mile

away, Project Tundra’s future is in doubt because it “would not fully comply with” the

Rule. Id. at 2, 16. That is because it was “designed” to capture only 70% of emissions

from the plant’s two existing generating units. Id. at 13. Project Tundra’s design alone

“took almost nine years of study and engineering.” Id. at 16. The Rule would require

Minnkota to ditch those plans and either draw up new designs or shutter the units.

Id. at 2.

Similarly, EPA relies on the Dry Fork Power Plant owned by NRECA member

Basin Electric Power Cooperative. E.g., 89 Fed. Reg. at 39,814. Basin completed a

CCS study two years ago, evaluating whether Dry Fork could target a “70% capture”

rate. App.689a (Basin Comments 19). The study concluded that even attempting this

70% milestone would be “prohibitively expensive—with total costs for the capture

system alone exceeding 1.5 billion dollars.” Id. In other words, attempting even 70%

capture “would exceed the costs . . . to actually construct the Dry Fork Station” itself.

Id. As with Boundary Dam and Project Tundra, EPA attempts to flip these facts on

their head, reasoning that a prohibitively expensive 70% CCS system that has not

been built somehow shows that 90% capture has already been adequately

demonstrated. E.g., 89 Fed. Reg. at 39,814.

Dry Fork and Project Tundra are also funded by the Energy Policy Act of 2005.

See id. at 39,849. That statute says “[n]o technology . . . shall be considered to be . . .

adequately demonstrated for purposes of” Section 111 “solely by reason of the use of

the technology . . . [at a] facilit[y] receiving assistance under” the statute. 42 U.S.C.

§ 15962(i)(1). So, if a project receives such funding, that project cannot be used as

necessary support for showing that a specific technology has been “adequately

demonstrated.” Id. Project Tundra and Dry Fork got that funding, so the Rule cannot

use them as necessary support. In fact, Project Tundra received public funding only

because it is attempting to demonstrate a technological feat—a full 70% CCS system—

that has not yet been achieved. See App.767a (Minnkota Comments 12).

A “system” that combines 90% carbon capture, transport, and

storage has not been “adequately demonstrated” anywhere.

Even if carbon capture, transport, or storage had been demonstrated in isolation,

these elements have not been adequately demonstrated as an integrated “system.” 42

U.S.C. § 7411(a)(1). This is yet another reason the Rule violates Section 111’s text.

First, EPA identifies only two power plants in North America that have ever used

a “system” combining capture, transport, and storage: Boundary Dam and Petra

Nova. 89 Fed. Reg. at 39,847. Both are coal-fired. See id. at 39,927. The flawed Petra

Nova experiment cannot show that CCS has been demonstrated for multiple reasons

discussed above (at p.16). Boundary Dam also cannot show that CCS has been

demonstrated. Apart from its limited capture discussed above (at p.16), it sells some

of the captured CO2, and transports the rest to a storage site just “2 km” away.

App.801a (Cichanowicz Comments 8). That storage site “is not subject to EPA’s . . .

Class VI rules for the storage of CO2.” App.852a (EERC Comments 8). By contrast,

EPA’s system requires units to: capture 90% of CO2, 89 Fed Reg. 39,846; transport

CO2 long distances, id. at 39,864; and store unsold CO2 in a “Class VI well[],” id. at

39,872.

Second, the Rule’s 90% CCS system would be exorbitantly costly even if it could

be built, and EPA failed to “tak[e] into account the cost” of such a system. 42 U.S.C.

§ 7411(a)(1). EPA counterfactually estimates that the Rule’s total compliance costs

are between 7.5 and 19 billion dollars. 89 Fed. Reg. at 40,005. But costs for Dry Fork’s

capture equipment alone (which planned to target only 70% capture) would exceed

“1.5 billion dollars.” App.689a (Basin Comments 19). That enormous cost is just for

one unit at one plant. Similarly, EPA says that the Rule will cause only a “one

percent” increase in the “levelized cost to produce electricity” nationwide. 89 Fed. Reg.

at 40,005. That is fanciful given Dry Fork’s cost projections alone, and EPA’s cost

estimates are off by orders of magnitude. NRECA’s comments and declarations

confirm this, showing that rural cooperatives would need to spend billions—

ultimately passing these costs on to consumers. See App.291-93a (NRECA Comments

18-20); App.346a (McCollam ¶11); App.412a (Purvis ¶43); App.479-80a (McLennan

¶82); App.488-89a (Tudor ¶8); App.527-28a (Hasten ¶31); App.553-54a (Grooms ¶28).

Third, EPA’s 90% CCS system also has not “been demonstrated” because EPA

failed to address the impact on electric reliability “energy requirements.” 42 U.S.C.

§ 7411(a)(1). Commenters alerted EPA to the “direct threats to electric grid

reliability.” E.g., App.275a, App.278-79a, App.299-305a (NRECA Comments 2, 5-6,

26-32). EPA responded by offering what it tellingly calls “compliance flexibilities.” 89

Fed. Reg. at 39,803. These discretionary possibilities include a one-year “compliance

date extension mechanism,” id. at 39,960; a “short-term reliability mechanism,” id.

at 40,014; and a “reliability assurance mechanism,” id. at 40,017. EPA cannot

sidestep its duty to set standards that account for energy requirements, 42 U.S.C.

§ 7411(a)(1), by directing regulated parties to seek discretionary dispensations. See,

e.g., Util. Air Regul. Grp. v. EPA, 573 U.S. 302, 326-27 (2014).

The Rule’s emissions limits are not “achievable.”

The Rule’s emissions limits are also unlawful because they are not “achievable.”

42 U.S.C. § 7411(a)(1). EPA used the undemonstrated 90% CCS “system” to set a

“standard” for new units and a “presumptive standard” for existing units. 89 Fed.

Reg. at 39,801; see id. at 39,956. These standards take the form of an emissions cap:

units must achieve an “an 88.4 percent reduction in annual emission rate.” Id. at

39,801 (existing coal-fired units); see id. at 39,802 (same for new gas-fired units).

A standard is “achievable” only if the system is “available for installation,”

Portland Cement, 486 F.2d at 391, to “the industry as a whole,” Nat’l Lime Ass’n v.

EPA, 627 F.2d 416, 431 (D.C. Cir. 1980). EPA must “identify variable conditions that

might contribute to” the standard’s nationwide achievability, and “establish that” it

used data “representative of potential industry-wide performance.” Sierra Club, 657

F.2d at 377 (emphases added); see 89 Fed. Reg. at 39,835 (same). As EPA’s former

New Source Review Section Chief once explained, a standard of performance under

Section 111 “represents the best technology available nationwide, regardless of

climate, water availability, and many other variable case-specific factors”—so the

Rule’s standards should reflect “what every source can achieve, not the best that a

source could do.”4 This Rule fails that test.

First, the technology for attempting 90% capture is not “available for

installation.” Portland Cement, 486 F.2d at 391. The few CCS projects identified by

EPA are working to someday demonstrate sub-90% capture in an experimental

context. App.280a (NRECA Comments 7). Nor has EPA identified any non-CCS

system that could achieve the required “88.4 percent reduction in annual [CO2]

emission rate[s]” that EPA equates with its 90% CCS system. 89 Fed. Reg. at 39,801.

4 Ltr. from Gary McCutchen, EPA to Richard E. Grusnick Ala. Dep’t Env’t Mgmt.

(July 28, 1987), https://perma.cc/3CJM-WL9E.

Pipelines are missing too.5 Yet pipelines are required for any level of CCS,

because they are the necessary transport link between CO2 “capture” and CO2

“storage.” App.288-89a, App.296a (NRECA Comments 15-16, 23). Realizing EPA’s

vision would require an enormous pipeline infrastructure buildout in eight years.

EPA speculates that a network of CO2 pipelines “may develop” “in the coming years.”

89 Fed. Reg. at 39,855. While the Proposed Rule touted nearly 4,000 miles of newly

“announced” CO2 pipelines, 88 Fed. Reg. at 33,294, the lion’s share has since been

“delayed or canceled,” 89 Fed. Reg. at 39,861. This is unsurprising. Surveying,

permitting, right-of-way disputes, and protracted litigation are obstacles nationwide.

The CO2 pipelines that do exist are in limited areas and mostly transport CO2 to

enhance oil and gas extraction. See EPA Tech. Supp. at 34. EPA has therefore failed

to show that 90% CCS is “capable of being met under most adverse conditions which

can reasonably be expected to recur.” Nat'l Lime, 627 F.2d at 431 n.46.

Storage locations are similarly scarce or absent. See App.288-89a (NRECA

Comments 15-16). EPA dismisses this concern because it has identified “potential

geolog[y]” for storage within 100 kilometers of every state with existing units affected

by the Rule. 89 Fed. Reg. at 39,857; EPA Tech. Supp. at 33. But speculation about

“potential” storage does not make actual storage achievable. These “potential” sites

have not been permitted (or even studied), which takes years of design and

5 EPA itself offers a map that strikingly illustrates this absence. See EPA, Greenhouse

Gas Mitigation Measures for Steam Generating Units Technical Support Document

at 34 (April 2024), https://perma.cc/LEY3-VC2F (“EPA Tech. Supp.”).

engineering. 89 Fed. Reg. at 39,857. Even EPA acknowledges that these sites “would

require site-specific characterization to determine their suitability for geologic

sequestration and the potential capacity for storage.” Id. at 39,855 n.378. These are

not storage sites that can be used today, and EPA’s hope that they will materialize

by 2032 is unsubstantiated.

Second, EPA’s timelines are unrealistic and “cannot be achieved.” App.771a

(Minnkota Comments 16); see, e.g., App.278-79a, App.296-97a (NRECA Comments 56, 23-24). Start with carbon capture. For Project Tundra, the Nation’s leading effort

to realize CCS, “project development took almost nine years of study and engineering

analysis.” App.771a (Minnkota Comments 16). Yet EPA says that sources across the

country can develop brand-new, never-before-used 90% CCS systems in less time

than it took just to plan Tundra. Even “Project Tundra would not be completed in the

time EPA has proposed, had the project begun today.” Id. If the Nation’s leading CCS

effort could not meet the Rule’s timelines, other units stand no chance.

Carbon transport has similar problems. EPA again relies on “unworkable

timelines that will be impossible to achieve.” App.275a (NRECA Comments 2). For

pipelines, just securing right-of-way can take many years of litigation. See App.85556a (EERC Comments 11-12). Furthermore, just “17 states explicitly allow CO2

pipeline operators to exercise eminent domain authority.” 89 Fed. Reg. at 39,858. In

the other 33, pipeline operators must rely on “negotiation with landowners.” Id.

EPA’s timelines for storage are likewise unachievable. For example, with Project

Tundra, “four years were required” just for permitting the storage site. App.771a

(Minnkota Comments 16). EPA allows just half that. 89 Fed. Reg. at 39,875. Yet the

90% CCS system would require a fully permitted sequestration site for every existing

“long-term” plant and every new “base load” plant that cannot sell the CO2 it

captures. 89 Fed. Reg. at 39,840, 39,902. This kind of storage requires a “Class VI”

underground-storage permit from EPA. See id. at 39,870. The “Class VI” permitting

rule took effect in 2011. Id. Since then, EPA has received 130 permit applications but

has issued only “eight Class VI permits.” Id. The rest are still pending. Id. EPA

dismisses this bottleneck because it “expect[s] . . . increased efficiencies” in the future.

Id. That speculation cannot show that storage is achievable today.

The Rule’s unachievable timelines are even further out of reach because, in

developing them, “EPA d[id] not assume that CCS projects are, in general, subject to

[the National Environmental Policy Act (NEPA)].” Id. at 39,875. CCS projects cannot

escape NEPA review and its accompanying delays. NEPA review is necessary for:

“sources receiving federal funding,” “projects on federal lands,” or where a federal

permit is necessary “for construction of the pipeline . . . or for sequestration.” Id.

According to EPA, “if one aspect of a project is subject to NEPA, then the other project

components could be as well.” Id. “NEPA review . . . averages more than four years.”

App.296a (NRECA Comments 23). NEPA requires that agencies “take a ‘hard look’

at the environmental consequences before taking a major action.” Baltimore Gas &

Elec. Co. v. Nat. Res. Def. Council, Inc., 462 U.S. 87, 97 (1983) (citation omitted). EPA

cannot just “assum[e]” those delays away. Contra 89 Fed. Reg. at 39,875.

The Rule’s emissions caps are especially unachievable for NRECA’s members. As

not-for-profit cooperatives, they cannot access the same financing available to forprofit utilities. App.277a (NRECA Comments 4). Instead, NRECA members must rely

on “debt sourced from entities such as the United States Department of Agriculture’s

(USDA) Rural Utilities Service.” Id. This financing itself can implicate NEPA, and it

is “unlikely to be secured until all permits are in place.” App.296a (NRECA

Comments 23). NRECA members must therefore work in stages—permitting first,

then procurement, then construction. This pushes timelines well beyond EPA’s

estimates. See, e.g., App.771-72a (Minnkota Comments 16-17).

Third, the Rule’s emission limits for other subcategories are not “achievable.” 42

U.S.C. § 7411(a)(1). Consider the second subcategory for existing coal-fired units,

which requires “medium-term” units to become combined coal and natural gas units

through co-firing natural gas for at least 40% of their fuel (and retire by 2039). 89

Fed. Reg. at 39,801. Many units cannot retrofit for co-firing. App.291a (NRECA

Comments 18). Even where co-firing might be technologically possible, the natural

gas pipelines needed to supply the large amount of fuel for co-firing have the same

regional variability and obstacles as CO2 pipelines. E.g., App.288a (NRECA

Comments 15). This technology is not “available for installation,” Portland Cement,

486 F.2d at 391, to “the industry as a whole,” Nat’l Lime, 627 F.2d at 431.

The Rule’s alternative compliance options unlawfully require

generation-shifting.

Under this Rule, if covered units cannot achieve an annual 90% CCS rate for the

entire unit, then they are forced to shift electricity generation to EPA’s preferred

sources. Supra p.12. Regardless of which subcategory applies, a covered unit that

cannot achieve 90% CCS must either retire completely, convert to another fuel and

then retire, or limit its output. E.g., 89 Fed. Reg. at 39,801. To make up the shortfall,

operators across the country will need to buy power from others or build new plants.

But this Court just held that the Clean Air Act does not grant EPA this authority:

The Clean Power Plan similarly required that “facilities reduce their own production

of electricity,” but EPA has no authority to “‘shift’ away virtually all their generation”

or “requir[e] coal plants to become natural gas plants.” West Virginia, 597 U.S. at 706,

728 & n.3. EPA styles its subcategories as “flexibilities” for an unachievable standard.

89 Fed. Reg. at 39,803. But no matter the agency’s label, all of this is prohibited

generation-shifting. See, e.g., Util. Air Regul. Grp., 573 U.S. at 326-27.

B. The major-questions doctrine confirms that the Rule is unlawful.

The Rule is unlawful under ordinary principles of statutory interpretation. See

supra Part I.A. But this is no ordinary case, because the major-questions doctrine

applies. See West Virginia, 597 U.S. at 723-24. EPA therefore needs “clear” statutory

language granting it the power asserted by this Rule. Id. at 732. Congress never used

clear language in Section 111 delegating EPA power to impose a system never before

accomplished or to force generation-shifting. Id. Nor did Congress use clear language

giving EPA the transformative power to remake the Nation’s energy grid through

future-looking “extrapolat[ions].” 89 Fed. Reg. at 39,889. Rather, Congress directed

the EPA to focus on what “has been adequately demonstrated” in the past. 42 U.S.C.

§ 7411(a)(1); see Carr, 560 U.S. at 448.

The Court below asserted that this case does not implicate the major questions

doctrine because “EPA has claimed only the power to set emissions limits under

Section 111 based on the application of measures that would reduce pollution by

causing the regulated source to operate more cleanly.” App.271a (internal quotation

omitted). But multiple independent factors confirm that “this is a major questions

case” of “vast economic and political significance.” West Virginia, 597 U.S. at 716, 724

(citation omitted).

First, the practical stakes are the same as in West Virginia. As NRECA’s

declarations make clear, covered units would have to spend billions—whether trying

to build a new 90% CCS system that no one has ever built before, or trying to address

the fallout from the shutdowns and curtailments demanded by the Rule. See

App.346a (McCollam ¶11); App.412a (Purvis ¶43); App.479-80a (McLennan ¶82);

App.488-89a (Tudor ¶8); App.527-28a (Hasten ¶31); App.553-54a (Grooms ¶28). Had

Congress wished to assign EPA a question involving “billions of dollars in spending

each year” affecting the price of electricity for millions of Americans, it “surely would

have done so expressly.” King v. Burwell, 576 U.S. 473, 485-86 (2015).

Second, EPA has not promulgated a run-of-the-mill regulation under Section

111—as the D.C. Circuit seemed to believe. It instead claims “newfound” and

“transformative” authority. West Virginia, 597 U.S. at 724 (citation omitted). EPA

has long set standards based on what has “been . . . demonstrated” in the past and is

“achievable” currently. West Virginia, 597 U.S. at 708; see 42 U.S.C. § 7411(a)(1). But

the Rule relies on projects with unknown capture rates that merely “ha[ve] been

announced,” 89 Fed. Reg. at 39,928; pipelines that EPA “anticipates . . . may develop,”

id. at 39,855; and potential storage sites “in the process of completing . . . studies,” id.

at 39,862. EPA rewrites the Act from focusing on what has been demonstrated in the

past to what the agency predicts will be possible in the future. This is an extravagant

power grab, regardless of whether this Rule would “caus[e] the regulated source to

operate more cleanly”—to quote the D.C. Circuit. App.271a.

Third, EPA claims “unprecedented power over American industry.” West

Virginia, 597 U.S. at 728 (citation omitted). By using an undemonstrated 90% CCS

“system” to set unachievable standards, the Rule forces electricity generation to shift

elsewhere. This is a monumental change that involves “balancing . . . many vital

considerations of national policy” in an arena where EPA has “no comparative

expertise.” Id. at 729 (citation omitted).

Fourth, mandatory CCS and generation-shifting are approaches that “Congress

[has] considered and rejected multiple times.” West Virginia, 597 U.S. at 731 (citation

omitted). Congress has supported development of CCS and other new generation

through voluntary funding incentives—not stringent mandates. See, e.g., Angela C.

Jones & Ashley J. Lawson, Cong. Rsch. Serv., Carbon Capture and Sequestration

(CCS) in the United States (Oct. 5, 2022), https://perma.cc/L73B-JXAW (discussing

tax credits for CCS). Congressional incentive programs lend no support for an

agency’s prescriptive mandates. E.g., NFIB v. OSHA, 595 U.S. 109, 119 (2022) (per

curiam). Congress has even rejected legislation that would require fossil-fuel

cessation or CCS at certain units. See, e.g., H.R. 2519, 117th Cong. (2021); H.R. 4535,

114th Cong. (2016); S. 4280, 117th Cong. (2022). The major-questions doctrine

precludes this Rule.

C. The Rule is arbitrary and capricious.

To top it off, the Rule is “arbitrary” and “capricious” in multiple ways. 5 U.S.C.

§ 706; see Ohio v. EPA, 144 S. Ct. at 2053.

First, EPA relied on CCS projects by NRECA members and others to support the

Rule’s 90% capture rate, while disregarding comments from the owners of those

projects who told the agency that this Rule places them in an “impossible position.”

App.764a (Minnkota Comments 9). For example, EPA relies heavily on Project

Tundra. E.g., 89 Fed. Reg. at 39,850-51. Minnkota “shares EPA’s enthusiasm for the

promise of . . . CCS” and—at least up until the Rule—was developing “the largest

capture system in the world” to help “prove that large scale coal-fired application is

possible.” App.765a, App.768a (Minnkota Comments 10, 13). But based on its

unmatched experience designing and planning for a CCS system, Minnkota

concluded that “EPA’s aspirational 90% value is clearly speculative and

unsupported.” App.768a (Minnkota Comments 13).

Similarly, EPA relies on NRECA member Basin’s Dry Fork unit. E.g., 89 Fed.

Reg. at 39,814. But Basin concluded that “Dry Fork Station show[s] that costs remain

prohibitively expensive and a significant impediment to the adoption of CCS” at any

level. App.687a (Basin Comments 17). It was arbitrary and capricious for the agency

to rely on these projects to show that 90% CCS “has been demonstrated” when the

owners themselves showed EPA that their as-yet-unbuilt units will not achieve that.

EPA’s reliance on Boundary Dam is likewise “not ‘reasonable’” and “[not]

‘reasonably explained.’” Ohio v. EPA, 144 S. Ct. at 2053 (quoting FCC v. Prometheus

Radio Project, 592 U.S. 414, 423 (2021)). EPA so badly misconstrued this project that

the owner filed comments to offer a “correction” of EPA’s misstatements. App.784a

(SaskPower Comments 1); see supra 14. EPA’s obstinate reliance on Boundary Dam

as a paragon of 90% CCS epitomizes unreasonable and unreasoned decisionmaking.

Second, EPA disregarded comments demonstrating that adequate pipelines for

CO2 transport do not exist and cannot be built by the Rule’s deadlines. See, e.g.,

App.685a (Basin Comments 15); see App.289-90a (NRECA Comments 16-17). EPA

instead asserted that, “in the coming years, a large-scale interstate pipeline network

may develop to transport CO2.” 89 Fed. Reg. at 39,855 (emphasis added). It speculated

that only “relatively short” pipelines would be needed, because most affected units

are in “relatively close proximity to deep saline formations that have the potential to

be used as long-term CO2 storage sites.” Id. (emphasis added). EPA cannot dismiss

commenters’ concerns by arguing that pipelines might be “relatively short” because

“potential” storage sites might someday be suitable. Id.

Third, NRECA and others emphasized that “geologic storage options[] . . . simply

do not exist” and cannot be sited, permitted, and constructed within the Rule’s

timelines. App.289a (NRECA Comments 16); see App.766a (Minnkota Comments 11).

EPA responded that “[m]any projects are in the process of completing thorough

subsurface studies of these deep saline formations to determine their suitability for

regional-scale storage.” 89 Fed. Reg. at 39,862. EPA cannot counter evidence that

storage sites “do not exist,” App.289a (NRECA Comments 16), with evidence that

studies may someday reveal these sites.

Fourth, EPA’s cost estimates for 90% CCS are fundamentally irrational, as

explained above (at p.23-24). Commenters highlighted the Rule’s massive compliance

costs. E.g., App.689a (Basin Comments 19); App.291-93a (NRECA Comments 18-20).

Yet EPA insists that units will actually earn net revenue by attempting to use an

undemonstrated 90% CCS system. E.g., 89 Fed. Reg. at 39,879. If that were true, then

a massive rulemaking would not be required. Electric utilities—especially cost34

sensitive rural electric cooperatives—would respond to market incentives even

absent government mandates. EPA’s cost conclusions are therefore not “logical and

rational.” Michigan v. EPA, 576 U.S. 743, 750 (2015) (citation omitted).

II. Applicant NRECA’s members will suffer substantial irreparable harms

absent a stay.

An immediate stay is necessary to protect NRECA’s members from the “hundreds

of millions, if not billions of dollars” in “nonrecoverable” compliance costs that they

will incur “during the pendency of this litigation.” Ohio v. EPA, 144 S. Ct. at 2053

(cleaned up); see NFIB, 595 U.S. at 120 (citing “billions of dollars in unrecoverable

compliance costs” to support stay of agency’s rule). NRECA’s members also face

“irreparable harm” from imminent power-plant shutdowns and the replacementpower costs, weakened energy-grid reliability, and skyrocketing energy rates that

will follow. Ala. Ass’n of Realtors v. HHS, 594 U.S. 758, 765 (2021) (per curiam).

A. NRECA’s individual members must incur billions of dollars in compliance

costs and other expenses to just attempt compliance with the Rule. See App.346a

(McCollam ¶11); App.412a (Purvis ¶43); App.479-80a (McLennan ¶82). Both CCS and

co-firing require massive capital investments. E.g., App.405-06a (Purvis ¶34) (“$10.7

billion” for CCS); App.413a (Purvis ¶45) (“$500 million” just for a new pipeline for cofiring). For example, Basin’s costs alone will exceed $14 billion. App.346a (McCollam

¶11).

This spending needs to start now. “Working backwards from the Final Rule’s

compliance dates, the engineering should have already begun.” App.377a (McCollam

¶64). Pipeline operators “must begin design, permitting, siting, procurement, and

construction immediately” to achieve co-firing by the Rule’s deadline. App.413-14a

(Purvis ¶46). EPA itself “assumes” the “work” toward achieving compliance will begin

in “June 2024.” 89 Fed. Reg. at 39,874. That is long before the expected “end of this

litigation,” Ohio v. EPA, 144 S. Ct. at 2053.

Speed is also imperative for NRECA’s not-for-profit electric cooperatives, because

they face unique delays in securing financing for these enormous compliance costs.

App.319-20a (Matheson ¶15). NRECA’s members have no shareholders, no access to

private-equity markets, and no recourse to municipal bonds. App.322-323a

(Matheson ¶21). They must issue debt that is recovered through rate hikes paid by

rural consumers. Id. At the same time, NRECA’s members will be on the hook for

debts related to electricity-generating assets forced into premature retirement by the

Rule. App.322a (Matheson ¶20); App.529-30a (Hasten ¶33) (stranded asset costs

exceeding $250 million); App.428-29a (Purvis ¶60) (remaining stranded asset debt of

$774.8 million upon shutdown in 2031). As a result, members’ “equity-to-totalcapitalization ratio will be adversely affected,” hurting their credit ratings and

increasing their cost of borrowing. App.325a (Matheson ¶25).

These harms are irreparable, because the expenditures are “nonrecoverable.”

Ohio v. EPA, 144 S. Ct. at 2053 (citation omitted). Bespoke equipment cannot be

returned. App.530a (Hasten ¶34). Dollars spent on design, permitting, engineering,

and studies cannot be refunded. App.595a (Porath ¶26). Long-term power supply

contracts cannot be discarded. App.499-500a (Tudor ¶26). Outstanding debts must be

repaid. App.336-37a (Matheson ¶42). And sovereign immunity precludes recovery

from the government. See Ohio v. EPA, 144 S. Ct. at 2053.

B. Where these new investments in CCS and co-firing cannot even be attempted,

shutting down is the only choice left. E.g., App.553a (Grooms ¶26) (“Imminent

retirement is the only option.”). Plans for new facilities that cannot satisfy EPA’s

unachievable mandates will also be abandoned. App.437-38a (McLennan ¶6).

Each megawatt of power lost to shutdowns or cancelled projects must be replaced.

E.g., App.571a (Grooms ¶54). Otherwise, the electric grid would collapse. See

App.432-33a (Purvis ¶66); App.471-72a (McLennan ¶66-67). But all forms of

replacement power are extremely expensive. E.g., App.553-54a (Grooms ¶28) ($1.3

billion to replace lost capacity); App.527-28a (Hasten ¶31) ($3 billion in replacementpower costs). Short-term fuel costs will spike even higher as suppliers prepare to lose

major purchasers because of premature retirements. App.616a (Soderberg ¶21);

App.363a (McCollam ¶39). These prices will only soar as operators rush to secure

replacement power to meet the demands from electric vehicles, data centers, and

countless other consumers. App.632-33a (Hochstetler ¶¶12-14); App.557-58a

(Grooms ¶34).

The resulting shortfall in capacity will pose an immediate threat to the already

vulnerable power grid. App.414a (Purvis ¶47) (“At a time when Kentucky has already

experienced rolling blackouts . . . based upon the existing resource portfolio, forcing

the arbitrary, premature closure of thousands of megawatts of existing baseload

capacity will place even greater strain on the ability of grid operators to keep power

flowing and meet demand.”); App.637a (Hochstetler ¶20) (“[W]ithout the addition of

new, always available generation, the utilities in South Carolina will likely be

incapable of providing generation to match demand during peak periods.”); App.37237

73a (McCollam ¶56) (“Systemic premature retirement of baseload EGUs increases

the likelihood of blackouts and other reliability failures.”).

The Court below dismissed all these harms and claimed that “a stay will not help

because the risk remains that the distant deadlines in EPA’s rule will come back into

force at the end of the case.” App.271a. But sources must inform States of their

federally enforceable commitment to retire in time for States to include them in their

plans under the Rule, which are due to EPA in May 2026. 89 Fed. Reg. at 40,056. And

EPA says work must begin in “June 2024.” Id. at 39,874. While the D.C. Circuit

expedited the briefing in this case, merits litigation including any potential review by

this Court is unlikely to be completed by May 2026. And a stay would alleviate the

high compliance costs of preparing for the farther-out deadlines, because those

deadlines must be tolled if a stay is issued.6

C. The Rule leaves NRECA’s members no choice but to dramatically increase

rates to cover their compliance costs and debt obligations. App.325-26a (Matheson

¶26). Because NRECA’s members serve rural communities, these costs will be spread

across fewer consumers than in more densely populated areas, and the impact on

individual households will be especially acute. App. 317-18a, App. 325-26a (Matheson

¶¶9, 26. One member estimates that electricity bills for households will double

because of the Rule. App.410-11a (Purvis ¶42); see also App.503a (Tudor ¶32)

See, e.g., EPA, Rulemaking to Amend Dates in Federal Implementation Plans

Addressing Interstate Transport of Ozone and Fine Particulate Matter, 79 Fed. Reg.

71,663 (Dec. 3, 2014) (delaying compliance deadlines by three years after D.C. Circuit

lifted stay of rule).

(estimating a 50% rate hike).

These debilitating rate hikes will fall upon the communities least able to absorb

the burden of higher energy bills. App.650a (Hollandsworth ¶8). Many of these

consumers already face “a daily choice between food, electricity, and medicine.”

App.388-89a (Purvis ¶7). For struggling households, these “staggering” increases are

simply “not possible.” App.410a (Purvis ¶40). But not-for-profit cooperatives have

nowhere else to turn to recoup the immense capital outlays necessary to comply with

the Rule.

III. The equities and relative harms favor a stay.

When “parties seek to stay the enforcement of a federal regulation against them,

often ‘the harms and equities [will be] very weighty on both sides.’” Ohio v. EPA, 144

S. Ct. at 2052 (quoting Labrador v. Poe, 144 S. Ct. 921, 929 (2024) (opinion of

Kavanaugh, J.)). In such cases, the resolution of a stay request “ultimately turns on

the merits.” Id. at 2053. At any rate, the balance of equities and harms also favors a

stay. “[O]ur system does not permit agencies to act unlawfully even in pursuit of

desirable ends.” Ala. Ass’n of Realtors, 594 U.S. at 766; see NFIB, 595 U.S. at 120.

Without a stay, NRECA’s members must begin making binding commitments

and taking other irreversible steps to comply with the Rule. EPA’s Rube Goldberg

machine of discretionary “compliance flexibilities” is of no use to those who have an

obligation to keep America’s lights on. EPA has a history of exploiting this dynamic

if its major rules are not stayed pending appellate review. E.g., EPA, In Perspective:

the Supreme Court’s Mercury and Air Toxics Rule Decision (June 30, 2015),

https://perma.cc/D9NK-CNBB (celebrating that “the majority of power plants are

already in compliance or well on their way to compliance” with rule that had just been

held unlawful in Michigan v. EPA, 576 U.S. 743 (2015)).

Electricity costs will skyrocket. App.305-06a (NRECA Comments 32-33); see

App.410a (Purvis ¶40). As existing units are shuttered and plans for new units are

abandoned, communities around the country will see jobs and tax revenue crater.

E.g., App.474-75a (McLennan ¶72). By targeting always-available generation from

coal- and gas-units (compared to intermittent forms like wind and solar), the Rule

threatens the reliable electricity supply. E.g., App.356a (McCollam ¶27); App.651a

(Hollandsworth ¶10). When that happens, investment dwindles, productivity

declines, competition freezes, and innovation stagnates. See App.642a (Hochstetler

¶33); App.432-33a (Purvis ¶66). An unreliable power grid also threatens public

health. App.432-33a (Purvis ¶66). NRECA members’ customers rely on electricity to

heat and cool their homes. Id. Medical providers depend on consistent power to treat

patients. Id. By forcing the premature retirement of reliable generation capacity, the

Rule exacerbates power outage risks during extreme weather events, which could

lead to increased morbidity among vulnerable populations. Id.

EPA’s unlawful Rule will inflict a multitude of irreparable harms on NRECA’s

not-for-profit members, who provide crucial energy to some of our Nation’s most in

need. This Court therefore should stay the Rule pending judicial review, preventing

EPA from once again jeopardizing the electricity grid’s reliability.

C ONCLUSION

The Court should grant the requested stay.

Dated: July 23, 2024

Respectfully submitted,

/s/ Scott A. Keller

Scott A. Keller

Counsel of Record

Steven P. Lehotsky

Michael B. Schon

Jacob B. Richards

LEHOTSKY KELLER COHN LLP

200 Massachusetts Ave. NW, Ste. 700

Washington, DC 20001

(512) 693-8350

scott@lkcfirm.com

Mithun Mansinghani

LEHOTSKY KELLER COHN LLP

629 W. Main St.

Oklahoma City, OK 73102

Joshua P. Morrow

LEHOTSKY KELLER COHN LLP

408 W. 11th St., 5th Floor

Austin, TX 78701

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.