UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

    ☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2024

OR

    ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to ___________________

Commission	Registrant; State of Incorporation;				I.R.S. Employer
File Number	Address; and Telephone Number				Identification No.
333-21011	FIRSTENERGY CORP.				34-1843785
	(An	Ohio	Corporation)
	76 South Main Street
	Akron		OH	44308
	Telephone		(800)	736-3402

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $0.10 par value	FE	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  ☑  No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes  ☑  No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☑
Accelerated Filer	☐
Non-accelerated Filer	☐
Smaller Reporting Company	☐
Emerging Growth Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐  No ☑

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

	OUTSTANDING
CLASS	As of June 30, 2024
Common Stock, $0.10 par value	575,922,417

FirstEnergy Website and Other Social Media Sites and Applications

FirstEnergy’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports, and all other documents filed with or furnished to the SEC pursuant to Section 13(a) of the Exchange Act are made available free of charge on or through the “Investors” page of FirstEnergy’s website at www.firstenergycorp.com. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.

These SEC filings are posted on FirstEnergy’s website as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Additionally, FirstEnergy routinely posts additional important information, including press releases, investor presentations, investor factbooks, regulatory activity updates, and notices of upcoming events under the “Investors” section of FirstEnergy’s website and recognizes FirstEnergy’s website as a channel of distribution to reach public investors and as a means of disclosing (including initially or exclusively) material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and Rich Site Summary feeds on the “Investors” page of FirstEnergy’s website. FirstEnergy also uses X (the social networking site formerly known as Twitter®), LinkedIn®, YouTube® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s website, X (the social networking site formerly known as Twitter®) handle, LinkedIn® profile, YouTube® channel or Facebook® page, and any corresponding applications of those sites, shall not be deemed incorporated into, or to be part of, this report.

Forward-Looking Statements: This Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 based on information currently available to management. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms):

•The potential liabilities, increased costs and unanticipated developments resulting from government investigations and agreements, including those associated with compliance with or failure to comply with the DPA.

•The risks and uncertainties associated with government investigations and audits regarding HB 6 and related matters, including potential adverse impacts on federal or state regulatory matters, including, but not limited to, matters relating to rates.

•The risks and uncertainties associated with litigation, arbitration, mediation and similar proceedings, particularly regarding HB 6 related matters, including risks associated with obtaining dismissal of the derivative shareholder lawsuits.

•Changes in national and regional economic conditions, including recession, volatile interest rates, inflationary pressure, supply chain disruptions, higher fuel costs, and workforce impacts, affecting us and/or our customers and those vendors with which we do business.

•Variations in weather, such as mild seasonal weather variations and severe weather conditions (including events caused, or exacerbated, by climate change, such as wildfires, hurricanes, flooding, droughts, high wind events and extreme heat events) and other natural disasters affecting future operating results and associated regulatory actions or outcomes in response to such conditions.

•Legislative and regulatory developments, including, but not limited to, matters related to rates, energy regulatory policies, compliance and enforcement activity, cyber security, and climate change.

•The risks associated with physical attacks, such as acts of war, terrorism, sabotage or other acts of violence, and cyber-attacks and other disruptions to our, or our vendors’, information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information.

•The ability to meet our goals relating to EESG opportunities, improvements, and efficiencies, including our GHG reduction goals.

•The ability to accomplish or realize anticipated benefits through establishing a culture of continuous improvement and our other strategic and financial goals, including, but not limited to, overcoming current uncertainties and challenges associated with the ongoing government investigations, executing Energize365, our transmission and distribution investment plan, executing on our rate filing strategy, controlling costs, improving credit metrics, maintaining investment grade ratings, and growing earnings.

•Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts may negatively impact our forecasted growth rate, results of operations, and may also cause us to make contributions to our pension sooner or in amounts that are larger than currently anticipated.

•Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets, including those sites impacted by the recently promulgated legacy CCR rules.

•Changes to environmental laws and regulations, including, but not limited to, rules recently finalized by the EPA and the SEC related to climate change.

•Changes in customers’ demand for power, including, but not limited to, economic conditions, the impact of climate change, emerging technology, particularly with respect to electrification, energy storage and distributed sources of generation.

•The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions.

•Future actions taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity.

•Changes in assumptions regarding factors such as economic conditions within our territories, the reliability of our transmission and distribution system, generation resource planning, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities.

•The potential of non-compliance with debt covenants in our credit facilities.

•The ability to comply with applicable reliability standards and energy efficiency and peak demand reduction mandates.

•Human capital management challenges, including among other things, attracting and retaining appropriately trained and qualified employees and labor disruptions by our unionized workforce.

•Changes to significant accounting policies.

•Any changes in tax laws or regulations, including, but not limited to, the IRA of 2022, or adverse tax audit results or rulings.

•The risks and other factors discussed from time to time in our SEC filings.

Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by the FE Board at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding our Climate Strategy, including our GHG emission reduction goals, are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding climate matters, including GHG emissions, may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.

TABLE OF CONTENTS

	Page
Part I. Financial Information
Glossary of Terms	ii
Item 1. Financial Statements
FirstEnergy Corp.
Consolidated Statements of Income	1
Consolidated Statements of Comprehensive Income	2
Consolidated Balance Sheets	3
Consolidated Statements of Equity	4
Consolidated Statements of Cash Flows	5
Notes To Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3. Quantitative and Qualitative Disclosures About Market Risk	78
Item 4. Controls and Procedures	78
Part II. Other Information
Item 1. Legal Proceedings	78
Item 1A. Risk Factors	78
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	78
Item 3. Defaults Upon Senior Securities	78
Item 4. Mine Safety Disclosures	79
Item 5. Other Information	79
Item 6. Exhibits	79

i

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of FE
AGC	Allegheny Generating Company, a generation subsidiary of MP
ATSI	American Transmission Systems, Incorporated, a transmission subsidiary of FET
CEI	The Cleveland Electric Illuminating Company, an Ohio electric power company subsidiary of FE
Electric Companies	OE, CEI, TE, FE PA, JCP&L, MP, and PE
FE	FirstEnergy Corp., a public electric power holding company
FE PA	FirstEnergy Pennsylvania Electric Company, a Pennsylvania electric power company subsidiary of FirstEnergy Pennsylvania Holding Company LLC, a wholly owned subsidiary of FE
FESC	FirstEnergy Service Company, which provides legal, financial, and other corporate support services
FET	FirstEnergy Transmission, LLC a consolidated VIE of FE, and the parent company of ATSI, MAIT and TrAIL, and having a joint venture in PATH
FEV	FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
Global Holding	Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC
JCP&L	Jersey Central Power & Light Company, a New Jersey electric power company subsidiary of FE
KATCo	Keystone Appalachian Transmission Company, a transmission subsidiary of FE
MAIT	Mid-Atlantic Interstate Transmission, LLC, a transmission subsidiary of FET
ME	Metropolitan Edison Company, a former Pennsylvania electric power company subsidiary of FE, which merged with and into FE PA on January 1, 2024
MP	Monongahela Power Company, a West Virginia electric power company subsidiary of FE
OE	Ohio Edison Company, an Ohio electric power company subsidiary of FE
Ohio Companies	CEI, OE and TE
PATH	Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH-Allegheny	PATH Allegheny Transmission Company, LLC
PATH-WV	PATH West Virginia Transmission Company, LLC
PE	The Potomac Edison Company, a Maryland and West Virginia electric power company subsidiary of FE
Penn	Pennsylvania Power Company, a former Pennsylvania electric power company subsidiary of OE, which merged with and into FE PA on January 1, 2024
Pennsylvania Companies	ME, PN, Penn and WP, each of which merged with and into FE PA on January 1, 2024
PN	Pennsylvania Electric Company, a former Pennsylvania electric power company subsidiary of FE, which merged with and into FE PA on January 1, 2024
Signal Peak	Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric power company subsidiary of FE
TrAIL	Trans-Allegheny Interstate Line Company, a transmission subsidiary of FET
Transmission Companies	ATSI, KATCo, MAIT and TrAIL
WP	West Penn Power Company, a former Pennsylvania electric power company subsidiary of FE, which merged with and into FE PA on January 1, 2024

ii

The following abbreviations and acronyms may be used to identify frequently used terms in this report:
2021 Credit Facilities	Collectively, the six separate senior unsecured five-year syndicated revolving credit facilities entered into by FE, the Electric Companies and the Transmission Companies, on October 18, 2021, as amended through October 20, 2023
2023 Credit Facilities	Collectively, the FET Revolving Facility and KATCo Revolving Facility
2026 Convertible Notes	FE’s 4.00% convertible senior notes, due 2026
A&R FET LLC Agreement	Fourth Amended and Restated Limited Liability Company Agreement of FET
ACE	Affordable Clean Energy
AEP	American Electric Power Company, Inc.
AFS	Available-for-sale
AFSI	Adjusted Financial Statement Income
AFUDC	Allowance for Funds Used During Construction
AMI	Advanced Metering Infrastructure
AMT	Alternative Minimum Tax
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
BGS	Basic Generation Service
Brookfield	North American Transmission Company II L.P., a controlled investment vehicle entity of Brookfield Infrastructure Partners
Brookfield Guarantors	Brookfield Super-Core Infrastructure Partners L.P., Brookfield Super-Core Infrastructure Partners (NUS) L.P., and Brookfield Super-Core Infrastructure Partners (ER) SCSp
CAA	Clean Air Act
CCR	Coal Combustion Residual
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CFIUS	Committee on Foreign Investments in the United States
CFR	Code of Federal Regulations
CO2	Carbon Dioxide
COVID-19	Coronavirus disease
CPP	EPA's Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DCR	Delivery Capital Recovery
DMR	Distribution Modernization Rider
DPA	Deferred Prosecution Agreement entered into on July 21, 2021 between FE and the U.S. Attorney’s Office for the S.D. Ohio
DSIC	Distribution System Improvement Charge
EDC	Electric Distribution Company
EE&C	Energy Efficiency and Conservation
EESG	Employee, Environmental, Social and Corporate Governance
EGS	Electric Generation Supplier
EGU	Electric Generation Unit
EH	Energy Harbor Corp.
ELG	Effluent Limitation Guideline
EmPOWER Maryland	EmPOWER Maryland Energy Efficiency Act
ENEC	Expanded Net Energy Cost
Energize365	FirstEnergy's Transmission and Distribution Infrastructure Investment Program
EnergizeNJ	JCP&L's second Infrastructure Investment Program
EPA	United States Environmental Protection Agency
EPS	Earnings Per Share
ESP	Electric Security Plan

iii

Exchange Act	Securities and Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FE Board	FE Board of Directors
FE Revolving Facility	FE and the Electric Companies’ former five-year syndicated revolving credit facility, as amended, and replaced by the 2021 Credit Facilities on October 18, 2021
FERC	Federal Energy Regulatory Commission
FET Board	FET Board of Directors
FET Equity Interest Sale	Sale of an additional 30% equity interest in FET that closed on March 25, 2024, such that Brookfield’s interest in FET increased from 19.9% to 49.9%
FET P&SA I	Purchase and Sale Agreement entered into on November 6, 2021, by and between FE, FET, Brookfield and the Brookfield Guarantors
FET P&SA II	Purchase and Sale Agreement entered into on February 2, 2023, by and between FE, FET, Brookfield, and the Brookfield Guarantors
FET Revolving Facility	FET’s five-year syndicated revolving credit facility, dated as of October 20, 2023
FIP	Federal Implementation Plan(s) under the CAA
Fitch	Fitch Ratings Service
FMB	First Mortgage Bond
FTR	Financial Transmission Right
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
HB 6	House Bill 6, as passed by Ohio's 133rd General Assembly
IRA of 2022	Inflation Reduction Act of 2022
IRS	Internal Revenue Service
KATCo Revolving Facility	KATCo’s four-year syndicated revolving credit facility, dated as of October 20, 2023
LOC	Letter of Credit
LTIIP	Long-Term Infrastructure Improvement Plan
MDPSC	Maryland Public Service Commission
MGP	Manufactured Gas Plants
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatt
MWh	Megawatt-hour
NCI	Noncontrolling Interest
N.D. Ohio	Federal District Court, Northern District of Ohio
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOL	Net Operating Loss
NOx	Nitrogen Oxide
NYPSC	New York State Public Service Commission
OAG	Ohio Attorney General
OCC	Ohio Consumers' Counsel
ODSA	Ohio Development Service Agency
Ohio Stipulation	Stipulation and Recommendation, dated November 1, 2021, entered into by and among the Ohio Companies, the OCC, PUCO Staff, and several other signatories
OOCIC	Ohio Organized Crime Investigations Commission, which is composed of members of the Ohio law enforcement community and is chaired by the OAG
OPEB	Other Post-Employment Benefits
OPIC	Other Paid-In Capital
OVEC	Ohio Valley Electric Corporation
PA Consolidation	Consolidation of the Pennsylvania Companies, effective January 1, 2024
PEER	FirstEnergy’s Program for Enhanced Employee Retirement
PJM	PJM Interconnection, LLC, an RTO
PJM Tariff	PJM Open Access Transmission Tariff

iv

PPA	Purchase Power Agreement
PPUC	Pennsylvania Public Utility Commission
PUCO	Public Utilities Commission of Ohio
Regulation FD	Regulation Fair Disclosure promulgated by the SEC
RFC	ReliabilityFirst Corporation
ROE	Return on Equity
RTO	Regional Transmission Organization
S.D. Ohio	Federal District Court, Southern District of Ohio
SEC	United States Securities and Exchange Commission
SEET	Significantly Excessive Earnings Test
SIP	State Implementation Plan(s) under the CAA
SLC	Special Litigation Committee of the FE Board
SO2	Sulfur Dioxide
SOFR	Secured Overnight Financing Rate
SOS	Standard Offer Service
SPE	Special Purpose Entity
S&P	Standard & Poor’s Ratings Service
Tax Act	Tax Cuts and Jobs Act adopted December 22, 2017
VIE	Variable Interest Entity
VSCC	Virginia State Corporation Commission
WVPSC	Public Service Commission of West Virginia

v

PART I. FINANCIAL INFORMATION

ITEM I.         Financial Statements

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(In millions, except per share amounts)	2024		2023		2024		2023
REVENUES:
Distribution services and retail generation	$	2,617	$	2,375	$	5,312	$	5,055
Transmission	579		518		1,094		978
Other	84		113		161		204
Total revenues(1)	3,280		3,006		6,567		6,237
OPERATING EXPENSES:
Fuel	128		140		233		273
Purchased power	877		894		1,913		2,018
Other operating expenses	1,170		885		2,176		1,731
Provision for depreciation	397		361		778		722
Deferral of regulatory assets, net	(8)		(33)		(172)		(113)
General taxes	293		278		604		574
Total operating expenses	2,857		2,525		5,532		5,205
OPERATING INCOME	423		481		1,035		1,032
OTHER INCOME (EXPENSE):
Debt redemption costs (Note 6)	(85)		(36)		(85)		(36)
Equity method investment earnings (Note 1)	22		35		43		91
Miscellaneous income, net	59		43		103		78
Pension and OPEB mark-to-market adjustment (Note 4)	—		59		—		59
Interest expense	(285)		(276)		(590)		(539)
Capitalized financing costs	29		22		59		43
Total other expense	(260)		(153)		(470)		(304)
INCOME BEFORE INCOME TAXES	163		328		565		728
INCOME TAXES	65		74		200		164
NET INCOME	$	98	$	254	$	365	$	564
Income attributable to noncontrolling interest	53		19		67		37
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP.	$	45	$	235	$	298	$	527
EARNINGS PER SHARE ATTRIBUTABLE TO FIRSTENERGY CORP. (Note 3):
Basic	$	0.08	$	0.41	$	0.52	$	0.92
Diluted	$	0.08	$	0.41	$	0.52	$	0.92
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	575		573		575		573
Diluted	576		574		576		574

(1) Includes excise and gross receipts tax collections of $98 million and $92 million during the three months ended June 30, 2024 and 2023, respectively, and $213 million and $201 million during the six months ended June 30, 2024 and 2023, respectively.

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

1

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(In millions)	2024		2023		2024		2023
NET INCOME	$	98	$	254	$	365	$	564
OTHER COMPREHENSIVE LOSS:
Pension and OPEB prior service credits	—		(1)		—		(3)
Amortized losses on derivative hedges	4		2		4		2
Other comprehensive income (loss)	4		1		4		(1)
Income tax benefits on other comprehensive income (loss)	1		1		1		—
Other comprehensive income (loss), net of tax	3		—		3		(1)
COMPREHENSIVE INCOME	$	101	$	254	$	368	$	563
Income attributable to noncontrolling interest	53		19		67		37
COMPREHENSIVE INCOME ATTRIBUTABLE TO FIRSTENERGY CORP.	$	48	$	235	$	301	$	526

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

2

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	June 30, 2024		December 31, 2023
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	60	$	137
Restricted cash	43		42
Receivables-
Customers	1,557		1,382
Less — Allowance for uncollectible customer receivables	54		64
	1,503		1,318
Other, net of allowance for uncollectible accounts of $14 in 2024 and $15 in 2023	297		266
Note receivable - Brookfield due 2024 (Note 1)	450		—
Materials and supplies, at average cost	536		512
Prepaid taxes and other	369		293
	3,258		2,568
PROPERTY, PLANT AND EQUIPMENT:
In service	51,356		50,107
Less — Accumulated provision for depreciation	14,218		13,811
	37,138		36,296
Construction work in progress	2,272		2,116
	39,410		38,412
INVESTMENTS AND OTHER NONCURRENT ASSETS:
Goodwill	5,618		5,618
Investments (Note 6)	670		663
Regulatory assets	405		369
Other	910		1,137
Note receivable - Brookfield due 2025 (Note 1)	750		—
	8,353		7,787
TOTAL ASSETS	$	51,021	$	48,767
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,325	$	1,250
Short-term borrowings	795		775
Accounts payable	1,477		1,362
Accrued interest	284		292
Accrued taxes	726		700
Accrued compensation and benefits	197		304
Customer deposits	228		227
Dividends payable	—		235
Other	324		241
	6,356		5,386
NONCURRENT LIABILITIES:
Long-term debt and other long-term obligations	20,831		22,885
Accumulated deferred income taxes	5,389		4,530
Retirement benefits	1,655		1,663
Regulatory liabilities	956		1,214
Other	2,106		2,173
	30,937		32,465
TOTAL LIABILITIES	37,293		37,851
EQUITY:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 575,922,417 and 574,335,396 shares outstanding as of June 30, 2024 and December 31, 2023, respectively.	58		57
Other paid-in capital	12,385		10,494
Accumulated other comprehensive loss	(14)		(17)
Retained earnings (Accumulated deficit)	45		(97)
Total common stockholders’ equity	12,474		10,437
Noncontrolling interest	1,254		479
TOTAL EQUITY	13,728		10,916
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
TOTAL LIABILITIES AND EQUITY	$	51,021	$	48,767

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

3

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

	Six Months Ended June 30, 2024
	Common stock			OPIC		AOCI		Retained earnings (Accumulated deficit)		Total Common Stockholders’ Equity		NCI		Total Equity
(In millions)	Shares	Amount
Balance, January 1, 2024	574	$	57	$	10,494	$	(17)	$	(97)	$	10,437	$	479	$	10,916
Net income	—	—		—		—		253		253		14		267
Stock Investment Plan and share-based benefit plans	2	—		9		—		—		9		—		9
Cash dividends declared on common stock ($0.425 per share in March)	—	—		(88)		—		(156)		(244)		—		(244)
FET Equity Interest Sale (Note 1)	—	—		1,942		—		—		1,942		731		2,673
Noncontrolling interest distributions declared	—	—		—		—		—		—		(8)		(8)
Balance, March 31, 2024	576	$	57	$	12,357	$	(17)	$	—	$	12,397	$	1,216	$	13,613
Net income	—	—		—		—		45		45		53		98
Other comprehensive income, net of tax	—	—		—		3		—		3		—		3
Stock Investment Plan and share-based benefit plans	—	1		20		—		—		21		—		21
Noncontrolling interest distributions declared	—	—		—		—		—		—		(7)		(7)
Other	—	—		8		—		—		8		(8)		—
Balance, June 30, 2024	576	$	58	$	12,385	$	(14)	$	45	$	12,474	$	1,254	$	13,728

	Six Months Ended June 30, 2023
	Common stock			OPIC		AOCI		Accumulated deficit		Total Common Stockholders’ Equity		NCI		Total Equity
(In millions)	Shares	Amount
Balance, January 1, 2023	572	$	57	$	11,322	$	(14)	$	(1,199)	$	10,166	$	477	$	10,643
Net income	—	—		—		—		292		292		18		310
Other comprehensive loss, net of tax	—	—		—		(1)		—		(1)		—		(1)
Stock Investment Plan and share-based benefit plans	1	—		19		—		—		19		—		19
Cash dividends declared on common stock ($0.39 per share in March)	—	—		(223)		—		—		(223)		—		(223)
Noncontrolling interest distributions declared	—	—		—		—		—		—		(17)		(17)
Balance, March 31, 2023	573	$	57	$	11,118	$	(15)	$	(907)	$	10,253	$	478	$	10,731
Net income	—	—		—		—		235		235		19		254
Stock Investment Plan and share-based benefit plans	—	—		22		—		—		22		—		22
Noncontrolling interest distributions declared	—	—		—		—		—		—		(36)		(36)
Balance, June 30, 2023	573	$	57	$	11,140	$	(15)	$	(672)	$	10,510	$	461	$	10,971

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

4

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months Ended June 30,
(In millions)	2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	365	$	564
Adjustments to reconcile net income to net cash from operating activities-
Depreciation, amortization and impairments	763		657
Charges associated with increase in ARO	207		—
Deferred income taxes and investment tax credits, net	165		133
Employee benefit costs, net	(13)		(7)
Pension trust contribution	—		(750)
Pension and OPEB mark-to-market adjustment	—		(59)
Transmission revenue collections, net	28		(65)
Changes in current assets and liabilities-
Receivables	(216)		110
Materials and supplies	(24)		(28)
Prepaid taxes and other current assets	(155)		(128)
Accounts payable	119		(303)
Accrued taxes	(111)		(64)
Accrued interest	(8)		29
Accrued compensation and benefits	(159)		(65)
Other current liabilities	49		(14)
Collateral, net	91		(190)
Employee benefit plan funding and related payments	(31)		(30)
Other	2		(3)
Net cash provided from (used for) operating activities	1,072		(213)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital investments	(1,732)		(1,418)
Sales of investment securities held in trusts	17		18
Purchases of investment securities held in trusts	(24)		(24)
Asset removal costs	(135)		(117)
Other	(2)		(6)
Net cash used for investing activities	(1,876)		(1,547)
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	400		2,600
Short-term borrowings, net	20		250
Redemptions and repayments-
Long-term debt	(1,386)		(515)
Proceeds from FET Equity Interest Sale (Note 1)	2,300		—
Noncontrolling interest cash distributions	(15)		(53)
Common stock dividend payments	(480)		(447)
Debt issuance and redemption costs, and other	(111)		(67)
Net cash provided from financing activities	728		1,768
Net change in cash, cash equivalents, and restricted cash	(76)		8
Cash, cash equivalents, and restricted cash at beginning of period	179		206
Cash, cash equivalents, and restricted cash at end of period	$	103	$	214
SUPPLEMENTAL CASH FLOW INFORMATION:
Significant non-cash transactions:
Accrued capital investments	$	230	$	143

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

5

FIRSTENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note Number		Page Number
1	Organization and Basis of Presentation	7
2	Revenue	10
3	Earnings Per Share	11
4	Pension and Other Post-Employment Benefits	12
5	Income Taxes	13
6	Fair Value Measurements	14
7	Variable Interest Entities	17
8	Asset Retirement Obligations	19
9	Regulatory Matters	20
10	Commitments, Guarantees and Contingencies	28
11	Segment Information	34

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.

FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries as of June 30, 2024: OE, CEI, TE, FE PA, JCP&L, FESC, MP, AGC (a wholly owned subsidiary of MP), PE and KATCo. Additionally, FET is a consolidated VIE of FE, and is the parent company of ATSI, MAIT, PATH and TrAIL. FE also holds all of the outstanding equity of other direct subsidiaries including FEV, which currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations.

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. FE PA serves an area with a population of approximately 4.5 million and operates under the rate districts of the former Pennsylvania Companies. FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.

Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.

FESC provides legal, financial and other corporate support services at cost, in accordance with its cost allocation manual, to affiliated FirstEnergy companies. FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries for services received from FESC either through direct billing or through an allocation process. Allocated costs are for services that are provided on behalf of more than one company and are allocated using formulas developed by FESC. Intercompany transactions are generally settled under commercial terms within thirty days.

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s electric operating companies comprise one of the nation’s largest investor-owned electric systems, serving over 6 million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include more than 24,000 miles of lines and two regional transmission operation centers. AGC and MP control 3,599 MWs net maximum capacity.

FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements as of June 30, 2024 and the three and six months ended June 30, 2024 and 2023 are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The December 31, 2023 Consolidated Balance Sheets were derived from audited financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period.

FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the Annual Report on Form 10-K for the year ended December 31, 2023.

FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. FE and its subsidiaries consolidate a variable interest entity when it is determined that it is the primary beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE’s ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.

Certain prior year amounts have been reclassified to conform to the current year presentation. During the first quarter of 2024, FirstEnergy’s segment reporting structure was modified to increase transparency for leadership and investors, simplify the

7

presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. The modification to the segments resulted in a reallocation of goodwill between the segments based on the relative fair value of the reporting units, as described further below. Disclosures for FirstEnergy's reportable operating segments for 2023 have been reclassified to conform to the current presentation reflecting the new reportable segments. In addition, on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and for comparability, prior year results in the Stand-Alone Transmission segment reflect the earnings and results of those WP transmission assets.

Economic Conditions

Post-pandemic economic conditions have stabilized across numerous material categories, but lead times have not returned to pre-pandemic levels. Several key suppliers have seen improvements with labor shortages and raw material availability and FirstEnergy continues to monitor the situation as capacity can be constrained with increased demand. Inflationary pressures have moderated, which has positively impacted the cost of materials, but certain categories have remained elevated. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect service disruptions or any material impact on its capital investment plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.

FET Noncontrolling Interest

FirstEnergy presents Brookfield’s ownership portion of FET’s net income and net assets as NCI. NCI is included as a component of equity on FirstEnergy’s Consolidated Balance Sheets.

On May 31, 2022, Brookfield acquired 19.9% of the issued and outstanding membership interests of FET. On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes. Interest income associated with the promissory notes was $20 million and $21 million for the three and six months ended June 30, 2024, respectively, and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET. The difference between the purchase price, net of transaction costs and deferred taxes of approximately $30 million and $797 million, respectively, and the carrying value of the NCI of $731 million, was recorded as an increase to OPIC by $1.9 billion during the first quarter of 2024.

Pursuant to the terms of the FET P&SA II, in connection with the closing, Brookfield, FET and FE entered into the A&R FET LLC Agreement, which amended and restated in its entirety the Third Amended and Restated Limited Liability Company Agreement of FET. The A&R FET LLC Agreement, among other things, provides for the governance, exit, capital and distribution, and other arrangements for FET from and following the closing. Under the A&R FET LLC Agreement, as of the closing, the FET Board consists of five directors, two of whom are appointed by Brookfield and three of whom are appointed by FE.

Capitalized Financing Costs

For the three months ended June 30, 2024 and 2023, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $13 million and $11 million, respectively, of allowance for equity funds used during construction and $16 million and $11 million, respectively, of capitalized interest.

For the six months ended June 30, 2024 and 2023, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $26 million and $19 million, respectively, of allowance for equity funds used during construction and $33 million and $24 million, respectively, of capitalized interest.

Equity Method Investments

Investments over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an Investment on the Consolidated Balance Sheets. The percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income and reflected in “Other Income (Expense)”.

Equity method investments included within "Investments" on the Consolidated Balance Sheets were approximately $108 million and $104 million as of June 30, 2024 and December 31, 2023, respectively.

8

Global Holding - FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales primarily focused on international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture’s economic performance. FEV's ownership interest is subject to the equity method of accounting. For the three months ended June 30, 2024 and 2023, pre-tax income related to FEV’s ownership in Global Holding was $21 million and $35 million, respectively, and $42 million and $89 million for the six months ended June 30, 2024 and 2023, respectively. FEV’s pre-tax equity earnings and investment in Global Holding are included in Corporate/Other for segment reporting.

As of June 30, 2024, and December 31, 2023, the carrying value of the equity method investment was $68 million and $66 million, respectively. During the six months ended June 30, 2024 and 2023, FEV received cash dividends from Global Holding of $40 million and $90 million, respectively, which were classified with “Cash from Operating Activities” on the Consolidated Statements of Cash Flows.

PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland, which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of June 30, 2024 and December 31, 2023, the carrying value of the equity method investment was $17 million.

Facility Optimization

FirstEnergy continues implementing its facility optimization plans focused on cost savings and alignment with our flexible working arrangements and EESG priorities. Beginning later this year, this will result in exiting the general office in Akron, Ohio, and other corporate facilities in Brecksville, Ohio, Greensburg, Pennsylvania, and Morristown, New Jersey. In December 2023, FirstEnergy purchased the general office building with the intention to sell in the future. Subject to certain FE required approvals, such sale may occur in 2025. The corporate headquarters will remain in Akron, Ohio, moving to the west Akron campus, and FirstEnergy continues to explore real estate options and relocation opportunities for the other corporate facilities. As FirstEnergy continues to transform the business and implement initiatives to reduce costs, including the facility optimization plan, the impact of such actions may result in future impairments or other charges that may be significant. The result of these combined efforts will help build a stronger, more sustainable company for the near and long term.

Goodwill

In accordance with GAAP, the modification to the segments in the first quarter of 2024 resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to regularly assess performance of the business and allocate resources.

The fair values of the reporting units were calculated using a discounted cash flow analysis. Key assumptions incorporated in the discounted cash flow analysis included discount rates, growth rates, projected operating income, changes in working capital, projected capital investments, and terminal multiples. The discounted cash flow analysis was also utilized to complete an impairment assessment before and after the segment change, with no impairment of goodwill indicated.

FirstEnergy's reporting units are consistent with its reportable segments and consist of Distribution, Integrated and Stand-Alone Transmission. The following table presents goodwill by reporting unit as of June 30, 2024:

(In millions)	Distribution Segment		Integrated Segment		Stand-Alone Transmission Segment		FirstEnergy Consolidated
Goodwill	$	3,222	$	1,953	$	443	$	5,618

New Accounting Pronouncements

Recently Issued Pronouncements - FirstEnergy is currently assessing the impact of new authoritative accounting guidance issued by the FASB that has not yet been adopted and the impact it will have on its financial statements and disclosures, as well as the potential to early adopt where applicable. The current expectation is that such new standards will not significantly impact FirstEnergy's financial reporting.

Recently Adopted Pronouncements - ASU 2022-03, "Fair Value Measurements of Equity Securities Subject to Contractual Sale Restrictions " (Issued in June 2022): ASU 2022-03 clarifies current guidance in Topic 820, Fair Value Measurement, when measuring the fair value of an equity security subject to contractual restrictions that prohibit the sale of an equity security, and introduces new disclosure requirements for those equity securities subject to contractual restrictions. FirstEnergy adopted ASU 2022-03 on January 1, 2024 with no material impact to its financial statements.

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2. REVENUE

The following represents a disaggregation of revenue from contracts with customers for the three and six months ended June 30, 2024 and 2023:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2024		2023		2024		2023
Distribution
Retail generation and distribution services
Residential	$	1,054	$	967	$	2,238	$	2,138
Commercial	384		374		758		751
Industrial	153		213		299		425
Other	18		17		38		34
Wholesale	1		11		2		13
Other revenue from contracts with customers	19		27		40		46
Total revenues from contracts with customers	1,629		1,609		3,375		3,407
Other revenue unrelated to contracts with customers	19		18		40		37
Total Distribution	$	1,648	$	1,627	$	3,415	$	3,444
Integrated
Retail generation and distribution services
Residential	$	578	$	423	$	1,152	$	929
Commercial	276		240		528		496
Industrial	147		133		285		268
Other	7		8		14		14
Wholesale	38		50		68		95
Transmission	116		86		197		150
Other revenue from contracts with customers	8		6		13		12
Total revenues from contracts with customers	1,170		946		2,257		1,964
Other revenue unrelated to contracts with customers	8		10		16		20
Total Integrated	$	1,178	$	956	$	2,273	$	1,984
Stand-Alone Transmission
ATSI	$	261	$	241	$	504	$	467
TrAIL	71		66		138		132
MAIT	110		98		214		187
KATCo	23		27		43		42
Other	(2)		$	—	(2)		—
Total revenues from contracts with customers	463		432		897		828
Other revenue unrelated to contracts with customers	5		4		9		8
Total Stand-Alone Transmission	$	468	$	436	$	906	$	836
Corporate/Other, Eliminations and Reconciling Adjustments
Wholesale	$	1	$	3	$	4	$	5
Eliminations and reconciling adjustments	(15)		(16)		(31)		(32)
Total Corporate/Other, Eliminations and Reconciling Adjustments	$	(14)	$	(13)	$	(27)	$	(27)
FirstEnergy Total Revenues	$	3,280	$	3,006	$	6,567	$	6,237

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Customer Receivables

Receivables from contracts with customers include distribution services and retail generation sales to residential, commercial and industrial customers of the Electric Companies. Billed and unbilled customer receivables as of June 30, 2024, and December 31, 2023, are included below:

Customer Receivables	June 30, 2024		December 31, 2023
	(In millions)
Billed	$	816	$	717
Unbilled	741		665
	1,557		1,382
Less: Uncollectible Reserve	54		64
Total Customer Receivables	$	1,503	$	1,318

The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible customer receivables should be further adjusted in accordance with the accounting guidance for credit losses.

FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Electric Companies are able to utilize to ensure payment. FirstEnergy’s uncollectible risk on PJM receivables, resulting from transmission and wholesale sales, is minimal due to the nature of PJM’s settlement process and as a result there is no current allowance for doubtful accounts.

Activity in the allowance for uncollectible accounts on customer receivables for the six months ended June 30, 2024, and for the year ended December 31, 2023 are as follows:

	(In millions)
Balance, January 1, 2023	$	137
Provision for expected credit losses(1)	8
Charged to other accounts(2)	34
Write-offs	(115)
Balance, December 31, 2023	$	64
Provision for expected credit losses(1)	32
Charged to other accounts(2)	17
Write-offs	(59)
Balance, June 30, 2024	$	54

(1) Approximately $2 million and $(15) million of which was deferred for future recovery (refund) in the six months ended June 30, 2024 and the year ended December 31, 2023, respectively.

(2) Represents recoveries and reinstatements of accounts written off for uncollectible accounts.

3. EARNINGS PER SHARE

EPS is calculated by dividing earnings attributable to FE by the weighted average number of common shares outstanding.

Basic EPS is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.

Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible securities. The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the 2026 Convertible Notes is computed using the if-converted method.

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The following table reconciles basic and diluted EPS attributable to FE:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Reconciliation of Basic and Diluted EPS	2024		2023		2024		2023
(In millions, except per share amounts)
Earnings attributable to FE	$	45	$	235	$	298	$	527
Share count information:
Weighted average number of basic shares outstanding	575		573		575		573
Assumed exercise of dilutive awards	1		1		1		1
Weighted average number of diluted shares outstanding	576		574		576		574
EPS attributable to FE:
Basic EPS	$	0.08	$	0.41	$	0.52	$	0.92
Diluted EPS	$	0.08	$	0.41	$	0.52	$	0.92

For the three and six months ended June 30, 2024 and 2023, no shares from awards were excluded from the calculation of diluted shares outstanding, as their inclusion would have been antidilutive.

The dilutive effect of the 2026 Convertible Notes is limited to the conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted. For the three and six months ended June 30, 2024, there was no dilutive effect resulting from the 2026 Convertible Notes as the average market price of FE shares of common stock was below the initial conversion price of $46.81 per share.

4. PENSION AND OTHER POST-EMPLOYMENT BENEFITS

On May 12, 2023, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan, which was funded by FE. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2028, which based on various assumptions, including an expected rate of return on assets of 8.0%, is expected to be approximately $260 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily.

FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. The size of the voluntary contribution made on May 12, 2023, in relation to total pension assets triggered a remeasurement of the pension plan, and as a result, FirstEnergy recognized a non-cash, pre-tax pension mark-to-market adjustment gain of approximately $59 million in the second quarter of 2023. The pension mark-to-market adjustment primarily reflected higher than expected return on assets, partially offset by a 29 basis points decrease in the discount rate used to measure benefit obligations.

The components of FirstEnergy’s net periodic benefit costs (credits) for pension and OPEB were as follows:

Components of Net Periodic Benefit Costs (Credits)	Pension				OPEB
For the Three Months Ended June 30,	2024		2023		2024		2023
	(In millions)
Service costs	$	35	$	35	$	—	$	—
Interest costs	100		107		5		6
Expected return on plan assets	(132)		(142)		(9)		(8)
Amortization of prior service costs (credits)	—		1		—		(2)
Special termination benefits(1)	—		5		—		2
Pension and OPEB mark-to-market adjustment	—		(59)		—		—
Net periodic benefit costs (credits)	$	3	$	(53)	$	(4)	$	(2)
Net periodic benefit costs (credits), net of amounts capitalized	$	(15)	$	(70)	$	(3)	$	(3)

(1) Related to benefits provided in connection with the PEER program.

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Components of Net Periodic Benefit Costs (Credits)	Pension				OPEB
For the Six Months Ended June 30,	2024		2023		2024		2023
	(In millions)
Service cost	70		69		1		1
Interest cost	199		216		10		11
Expected return on plan assets	(265)		(270)		(17)		(16)
Amortization of prior service cost (credit)(1)	1		1		(1)		(4)
Special termination benefits(2)	—		5		—		2
Pensions & OPEB mark-to-market adjustment	—		(59)		—		—
Net periodic cost (credits)	5		(38)		(7)		(6)
Net periodic benefit costs (credits), net of amounts capitalized	$	(30)	$	(73)	$	(7)	$	(7)

(1) The income tax benefits associated with the pension and OPEB prior service costs amortized out of AOCI were $1 million for the six months ended June 30, 2023. Amounts were immaterial for the six months ended June 30, 2024.

(2) Related to benefits provided in connection with the PEER program.

Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within “Miscellaneous income, net”, within “Other Income (Expense)” on FirstEnergy’s Consolidated Statements of Income.

Cash flows from operating activities for the six months ended June 30, 2024 and 2023, includes approximately $31 million and $30 million, respectively, of employee benefit plan funding and related payments. These payments are primarily related to short-term benefit payment liabilities owed to retirees under plan obligations in the respective periods.

5. INCOME TAXES

FirstEnergy’s interim effective income tax rates reflect the estimated annual effective income tax rates for 2024 and 2023. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as certain discrete items. The following tables reconcile the effective income tax rate to the federal income tax statutory rate for the three and six months ended June 30, 2024 and 2023:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2024			2023			2024			2023
	(In millions)
Income before income taxes	$	163		$	328		$	565		$	728
Federal income tax expense at statutory rate (21%)	$	34		$	69		$	119		$	153
Increases (reductions) in tax expense resulting from:
Nondeductible SEC and OOCIC loss contingencies	27			—			27			—
State and municipal income taxes, net of federal tax benefit	21			19			43			43
AFUDC equity and other flow-through	(8)			(4)			(16)			(9)
Deferred taxes related to sale of equity interest in FET, net	—			—			7			—
Excess deferred tax amortization due to the Tax Act	(13)			(16)			(26)			(32)
Valuation allowances	(3)			—			36			—
Other, net	7			6			10			9
Total income taxes	$	65		$	74		$	200		$	164
Effective income tax rate	39.9		%	22.6		%	35.4		%	22.5		%

The IRA of 2022, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement NOLs can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury during 2022 and 2023, FirstEnergy continues to believe that it is more likely than not that AMT will be applicable beginning with 2023. The future issuance of U.S. Treasury regulations could

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significantly change FirstEnergy’s AMT estimates or its conclusion as to whether it is an AMT payer at all. Additionally, the regulatory treatment of the impacts of this legislation may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in this legislation, including guidance from the U.S. Treasury and/or the IRS or unfavorable regulatory treatment, could negatively impact FirstEnergy’s cash flows, results of operations, and financial condition. As further discussed below, FirstEnergy expects to pay regular federal corporate income tax in 2024, due in large part to the gain realized from closing the FET Equity Interest Sale.

As discussed above, on March 25, 2024, FirstEnergy closed on the FET Equity Interest Sale, realizing an approximate $7.3 billion tax gain from the combined sale of 49.9% of the membership interests in FET for the consideration received and recapture of negative tax basis in FET. In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% sale of FET in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA Consolidation. During the first quarter of 2024, FirstEnergy also recognized a reduction to OPIC of approximately $797 million for federal and state income tax associated with the tax gain from closing on the FET Equity Interest Sale. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards that will be used to offset a majority of the tax gain from the FET Equity Interest Sale and expected taxable income in 2024, however, due to certain limitations on NOL utilization enacted in the Tax Act, FirstEnergy expects that a portion of the NOL will carry into 2025 and possibly beyond. As a result of the FET Equity Interest Sale, FET and its subsidiaries deconsolidated from FirstEnergy’s consolidated federal income tax group and now constitute their own consolidated federal income tax group subject to their own income tax allocation agreement.

Due to a private letter ruling recently issued by the IRS to an unaffiliated utility company, FirstEnergy is evaluating the potential requirement to transition certain of its Electric Companies and Transmission Companies to stand-alone treatment of NOL carryforwards for ratemaking purposes. Currently, none of FirstEnergy’s Electric Companies or Transmission Companies have transitioned to stand-alone treatment. FirstEnergy expects that if and where transitioning is required, those impacted Electric Companies and Transmission Companies will make the appropriate regulatory filing(s) in their applicable jurisdiction to include the NOL carryforward deferred tax asset in rate base and revenue requirement, which could have a material, favorable impact on future net income.

6. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:

Level 1	-	Quoted prices for identical instruments in active market.
Level 2	-	Quoted prices for similar instruments in active market.
	-	Quoted prices for identical or similar instruments in markets that are not active.
	-	Model-derived valuations for which all significant inputs are observable market data.

Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3 - Valuation inputs are unobservable and significant to the fair value measurement.

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value.

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs’ carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs’ remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of June 30, 2024, from those used as of December 31, 2023. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty

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credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

The following table sets forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

	June 30, 2024								December 31, 2023
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets	(In millions)
Derivative assets FTRs(1)	$	—	$	—	$	10	$	10	$	—	$	—	$	4	$	4
Equity securities	2		—		—		2		2		—		—		2
U.S. state and municipal debt securities	—		271		—		271		—		275		—		275
Cash, cash equivalents and restricted cash(2)	103		—		—		103		179		—		—		179
Other(3)	—		50		—		50		—		40		—		40
Total assets	$	105	$	321	$	10	$	436	$	181	$	315	$	4	$	500
Liabilities
Derivative liabilities FTRs(1)	$	—	$	—	$	2	$	2	$	—	$	—	$	1	$	1
Total liabilities	$	—	$	—	$	2	$	2	$	—	$	—	$	1	$	1
Net assets	$	105	$	321	$	8	$	434	$	181	$	315	$	3	$	499

(1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

(2) Restricted cash of $43 million and $42 million as of June 30, 2024 and December 31, 2023, respectively, primarily relates to cash collected from MP, PE and the Ohio Companies’ customers that is specifically used to service debt of their respective securitization or funding companies.

(3) Primarily consists of short-term investments.

INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.

Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the spent nuclear fuel disposal trusts of JCP&L are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.

Spent Nuclear Fuel Disposal Trusts

JCP&L holds debt securities within the spent nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value. The trust is intended for funding spent nuclear fuel disposal fees to the United States Department of Energy associated with the previously owned Oyster Creek and Three Mile Island Unit 1 nuclear power plants.

The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in spent nuclear fuel disposal trusts as of June 30, 2024, and December 31, 2023:

	June 30, 2024(1)								December 31, 2023(2)
	Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value		Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value
	(In millions)
Debt securities	$	303	$	—	$	(32)	$	271	$	301	$	1	$	(27)	$	275

(1) Excludes short-term cash investments of $8 million as of June 30, 2024.

(2) Excludes short-term cash investments of $6 million December 31, 2023.

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Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three and six months ended June 30, 2024 and 2023, were as follows:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2024		2023		2024		2023
	(In millions)
Sale proceeds	$	4	$	17	$	17	$	18
Realized gains	—		—		—		—
Realized losses	(1)		(1)		(2)		(2)
Interest and dividend income	3		3		6		6

Other Investments

Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Earnings and losses associated with corporate-owned life insurance policies are reflected in “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. The total carrying value of other investments were $391 million and $382 million as of June 30, 2024, and December 31, 2023, respectively, and are excluded from the amounts reported above. See Note 1, "Organization and Basis of Presentation," for additional information on FirstEnergy's equity method investments.

For the three months ended June 30, 2024 and 2023, pre-tax income related to corporate-owned life insurance policies was $1 million and $3 million, respectively, and $10 million for the six months ended June 30, 2024 and 2023. Corporate-owned life insurance policies are valued using the cash surrender value and any changes in value during the period are recognized as income or expense.

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts as of June 30, 2024 and December 31, 2023:

	June 30, 2024		December 31, 2023
	(In millions)
Carrying value	$	23,268	$	24,254
Fair value	$	21,578	$	23,003

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of June 30, 2024, and December 31, 2023.

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FirstEnergy had the following issuances and redemptions during the six months ended June 30, 2024:

Company	Type	Redemption / Issuance Date	Interest Rate	Maturity	Amount (In millions)	Description
Redemptions
FE	Unsecured Notes	April, 2024	7.375%	2031	$463	FE redeemed all of its remaining $463 million of 2031 Notes, including a premium of approximately $80 million ($63 million after-tax). In addition, FE recognized approximately $4 million ($3 million after-tax) of deferred cash flow hedge losses and $1 million in other unamortized debt costs and fees associated with the FE debt redemptions.
JCP&L	Unsecured Notes	April, 2024	4.70%	2024	$500	JCP&L redeemed unsecured notes that became due.
MP	FMBs	April, 2024	4.10%	2024	$400	MP redeemed FMBs that became due.
Issuances
ATSI	Unsecured Notes	March, 2024	5.63%	2034	$150	Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MAIT	Unsecured Notes	May, 2024	5.94%	2034	$250	Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.

7. VARIABLE INTEREST ENTITIES

FirstEnergy performs qualitative analyses to determine whether a variable interest qualifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.

In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance.

Consolidated VIEs

Total assets on the FirstEnergy consolidated balance sheets include approximately $11.3 billion and $11.0 billion of consolidated VIE assets, as of June 30, 2024 and December 31, 2023, respectively, that can only be used to settle the liabilities of the applicable VIE. Total liabilities include approximately $8.5 billion and $7.8 billion as of June 30, 2024 and December 31, 2023, respectively, of consolidated VIE liabilities for which the VIE's creditors do not have recourse to FirstEnergy.

VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements):

Securitization Companies

•Ohio Securitization Companies - In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. The SPEs are considered VIEs and each one is consolidated into its applicable electric company. As of June 30, 2024 and December 31, 2023, $183 million and $191 million of the phase-in recovery bonds were outstanding, respectively.

•MP and PE Environmental Funding Companies - The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of June 30, 2024 and December 31, 2023, $203 million and $218 million of environmental control bonds were outstanding, respectively.

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Cash of $40 million as of June 30, 2024 and December 31, 2023 collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies is included in “Restricted cash” on the FirstEnergy Consolidated Balance Sheets.

FET

FET is a holding company that owns equity interests in ATSI, MAIT, TrAIL and PATH. As further discussed above, on February 2, 2023, FE entered into an agreement with Brookfield to sell an incremental 30% equity interest in FET, which closed on March 25, 2024. As of June 30, 2024, FE’s equity ownership in FET is 50.1% and Brookfield’s is 49.9%. FirstEnergy has concluded that FET is a VIE and that FE is the primary beneficiary because FE has exposure to the economics of FET and the power to direct significant activities of FET through the FESC services agreement, which represents a separate variable interest.

Although Brookfield was granted incremental consent rights upon the closing of the FET Equity Interest Sale, Brookfield will not have unilateral control over any activities that most significantly impact FET’s economic performance. However, FE will continue to retain power over the activities that most significantly impact FET’s economic performance through its incremental decision making rights under the existing FESC services agreement, through which executive management and workforce services are provided to FET. As a result, FE is the primary beneficiary of FET, which will continue to be consolidated in FirstEnergy’s financial statements.

The following shows the carrying amounts and classification of the FET assets and liabilities included in the consolidated financial statements as of June 30, 2024 and December 31, 2023. Amounts exclude intercompany balances which were eliminated in consolidation. The assets of FET can only be used to settle its obligations, and creditors of FET do not have recourse to the general credit of FirstEnergy.

Assets	June 30, 2024		December 31, 2023
	(In millions)
Cash and cash equivalents	$	10	$	76
Receivables	114		88
Materials and supplies, at average cost	1		1
Prepaid taxes and other	18		23
Total current assets	143		188
Property, plant and equipment, net	10,645		10,227
Goodwill	224		224
Investments	19		19
Regulatory assets	7		16
Other	173		310
Total noncurrent assets	11,068		10,796
TOTAL ASSETS	$	11,211	$	10,984

Liabilities	June 30, 2024		December 31, 2023
	(In millions)
Currently payable long-term debt	$	1,225	$	—
Short-term borrowings	215		—
Accounts payable	—		2
Accrued interest	68		63
Accrued taxes	295		262
Other	7		14
Total current liabilities	1,810		341
Long-term debt and other long-term obligations	4,449		5,275
Accumulated deferred income taxes	1,341		1,218
Regulatory liabilities	349		307
Other	149		285
Total noncurrent liabilities	6,288		7,085
TOTAL LIABILITIES	$	8,098	$	7,426

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Unconsolidated VIEs

FirstEnergy is not the primary beneficiary of its equity method investments in Global Holding and PATH WV, as further discussed above, or its PPAs.

FirstEnergy evaluated its PPAs and determined that certain Non-Utility Generation entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. As of June 30, 2024, FirstEnergy maintains four long-term PPAs with Non-Utility Generation entities that were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE.

Because FirstEnergy has no equity or debt interests in the Non-Utility Generation entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power, which are expected to be recovered from customers.

8. ASSET RETIREMENT OBLIGATIONS

FirstEnergy recognizes an ARO for its legal obligation to perform asset retirement activities associated with its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation such that the ARO is accreted monthly to reflect the time value of money.

A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the remediation AROs, taking into account the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. For instances where asset retirement costs relate to assets that have no future cash flows, the costs are recorded as an operating expense. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition.

FirstEnergy has recognized applicable legal obligations for AROs and their associated costs, including reclamation of sludge disposal ponds, closure of CCR sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.

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The following table summarizes the changes to the ARO balances as of June 30, 2024 and December 31, 2023:

ARO Reconciliation	(In millions)
Balance, January 1, 2023	$	185
Changes in timing and amount of estimated cash flows	10
Liabilities settled	(2)
Accretion	16
Balance, December 31, 2023	$	209
Changes in timing and amount of estimated cash flows	117
Liabilities incurred	95
Liabilities settled	(2)
Accretion	9
Balance, June 30, 2024	$	428

On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of June 30, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. AE Supply continues to evaluate closure options for McElroy’s Run and the adjacent landfill, including the potential transfer of the site and remediation obligations to a third-party as well as other interpretation changes to its closure plans. As a result, during the second quarter of 2024, AE Supply reviewed its ARO and future expected costs to remediate McElroy’s Run and the adjacent dry landfill, resulting in an increase to the ARO liability and corresponding increase to “Other operating expense” of $87 million at Corporate/Other for segment reporting. Final acceptance of the closure plan or the transfer of the obligation to a third-party could result in further adjustments to the ARO recognized by FirstEnergy.

As further discussed below, on May 8, 2024, the EPA finalized changes to the CCR rule addressing certain legacy CCR disposal sites which were not included in previous CCR rules. During the second quarter of 2024, FirstEnergy performed a preliminary assessment of former CCR disposal sites and calculated an initial estimate applying historical experience in remediating comparable sites. As a result, FirstEnergy recorded a $125 million increase to its ARO, of which $120 million is included in “Other operating expenses” on the Consolidated Statements of Income and was not capitalized as an asset retirement cost since the associated plants do not have future cash flows. Of the $120 million, $16 million is included with Integrated, $46 million is included within Distribution and $58 million at Corporate/Other for segment reporting.

The ARO increase related to certain legacy CCR disposal sites represents the discounted cash flows for estimated closure costs based upon the potential closure requirements as evaluated on a site-by-site basis. Actual costs to be incurred will be dependent upon factors that vary from site to site. The most significant factors include the method and time frame of closure at the individual sites, which will be determined based on the groundwater monitoring and, if applicable, EPA approval of closure plans. In determining the estimated closure costs for each site, FirstEnergy has assumed the anticipated applicable closure method, however, alternative closure methods may be required, resulting in greater or lesser cost. As a result, the ARO liability may be adjusted as additional information is gained through the evaluation and closure process, including further inspection of the sites, results of groundwater monitoring and changes in interpretation of the CCR regulations which may change management assumptions, and could result in a material change to the ARO liability balance and FirstEnergy’s results of operations.

9. REGULATORY MATTERS

STATE REGULATION

Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

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MARYLAND

PE operates under MDPSC approved base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.

The EmPOWER Maryland program previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. PE recovers EmPOWER program costs with a return on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding. Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025, and 100% in 2026 and beyond. Notwithstanding the order to phase out the unamortized balances of EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and was to be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the unamortized balances was extended through the end of 2030. On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years. New legislation signed into law on May 9, 2024, and effective July 1, 2024, is expected to reduce the pre-tax return on the EmPOWER Maryland programs for PE by a total of $25 to $30 million over the period of 2024-2030.

NEW JERSEY

JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third- party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

The base rate increase approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and became effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L was amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.

JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On May 22, 2024, the NJBPU approved JCP&L’s request for a six-month extension of the EE&C Plan I, to December 31, 2024. The budget for the extension period adds approximately $69 million to the original program cost and JCP&L will recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and has a proposed budget of approximately $964 million. EE&C Plan II consists of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. Public hearings were held on June 11, 2024, and the parties are currently engaged in settlement discussions. On July 1, 2024, the NJBPU suspended the procedural schedule. A final NJBPU decision and order is required no later than October 15, 2024.

The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes

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and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L and one other party filed comments on July 31, 2023.

On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. At this time, Orsted’s announcement does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.

Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the United States Department of Energy to finance a portion of the project using low-interest rate loans available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024, which was approved on May 17, 2024.

On April 3, 2024, Mid-Atlantic Offshore Development, LLC submitted a bid application for the NJBPU Prebuild Infrastructure Solicitation to the NJBPU which outlines its proposal to construct infrastructure connecting the identified landing point for offshore wind generation off the coast of New Jersey with the high-voltage electric grid at Larrabee Collector Station. JCP&L was described in the application as a joint developer with Mid-Atlantic Offshore Development, LLC, subject to the execution of a joint development agreement by the parties. Mid-Atlantic Offshore Development, LLC would have been the party responsible for the project. Mid-Atlantic Offshore Development, LLC, is no longer advancing its application to the NJBPU for the Prebuild Infrastructure Solicitation.

On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, as amended, if approved will result in the investment of approximately $930.5 million of total estimated costs over five years.

OHIO

The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continued the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with revenue cap increases of $15 million per year through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.

On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies request a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, and reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, the Ohio

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Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony and expect by month-end to file an update with an adjusted net increase of base distribution revenues and incorporating matters in the rate case as directed by the PUCO’s ESP V Order.

On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications. ESP V, as modified by the PUCO, became effective June 1, 2024 and continues through May 31, 2029, and provides for, among other things, the continuation of existing riders related to purchased power, transmission and uncollectibles, the continuation of the DCR rider with proposed annual revenue cap increases until new base rates are established, the continuation of the AMI rider, and the addition of new riders for storm recovery and vegetation management, with terms and conditions to be established in the base rate case. The ESP V order additionally directed the Ohio Companies to file another base distribution rate case not later than May 31, 2028, develop an electric vehicle education program to assist customers in transitioning to electric vehicles and contribute $32.5 million during the term of ESP V to fund low-income customer bill assistance programs and bill assistance for income-eligible senior citizens, which was recognized in the second quarter of 2024 within “Other operating expenses” at the Regulated Distribution segment and on FirstEnergy’s Consolidated Statements of Income. On June 14, 2024, the Ohio Companies filed an Application for Rehearing seeking greater certainty regarding the key terms of ESP V over the approved term and proposed modifications to the May 15, 2024 order. The Ohio Companies also proposed modifications to ESP V to resolve their Application for Rehearing including, among other things, a reduced three-year ESP V term, approval of certain riders over the full three-year proposed ESP V term, full recovery of investments in the DCR and proposed modifications to preserve the economic value of the Order for customers, including a commitment to forego pursuit of the Ohio Companies' request for an enhanced vegetation management program in the 2024 base distribution rate case. Other parties also filed applications for rehearing. All applications for rehearing remain pending before the PUCO.

On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2023, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2024, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2023, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. These matters remain pending before the PUCO.

On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 15, 2024, the Ohio Companies filed a motion to consolidate their phase two distribution grid modernization plan proceeding with three audit proceedings pending before the PUCO, which was granted on May 23, 2024. Evidentiary hearings began on June 5, 2024 and concluded on July 2, 2024.

On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below and set a procedural schedule, which was vacated on March 15, 2024. On June 21,

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2024, the Attorney Examiners issued an entry setting a procedural schedule, which was modified on July 16, 2024. Evidentiary hearings are scheduled to begin February 3, 2025.

On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the DCR rider audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner directed the third-party auditor to file its report by August 28, 2024.

In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiners set a procedural schedule, which was vacated on March 15, 2024. On June 21, 2024, the Attorney Examiners issued an entry setting a procedural schedule and scheduling evidentiary hearings to begin October 9, 2024.

In connection with an ongoing annual audit of the Ohio Companies’ DCR rider for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through the DCR rider or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement, and set a procedural schedule, which was vacated on March 15, 2024. On June 21, 2024, the Attorney Examiners issued an order setting a procedural schedule, which was modified on July 16, 2024. Evidentiary hearings are scheduled to begin February 3, 2025.

On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or the, now-deceased, former chairman of the PUCO through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered.

On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing.

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In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.

See Note 10, “Commitments, Guarantees and Contingencies” below for additional details on the government investigations and ongoing litigation surrounding the investigation of HB 6.

PENNSYLVANIA

The Pennsylvania Companies operated under rates approved by the PPUC, effective as of January 27, 2017. On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.

Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the next phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period beginning January 1, 2025 and ending December 31, 2029.

On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.

On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requests a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing include a proposal to change pension recovery from average cash contributions to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requests an enhanced ten year vegetation management program and recovery of certain incurred costs, including major storms, COVID-19, a program to convert streetlights to LEDs, and others. The PPUC issued an order on April 25, 2024, deferring, by operation of law, the June 1, 2024 statutory effective date to January 1, 2025. A pre-hearing conference was held on May 2, 2024, at which time the procedural litigation schedule was set. Hearings are scheduled to begin August 15, 2024. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually.

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On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, includes the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 will be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.

On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. The first solar generation site went into service in January 2024 and construction of the remaining four sites are expected to be completed no later than the end of 2025 at a total investment cost of approximately $110 million. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024.

On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE were seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and new depreciation rates became effective on March 27, 2024.

On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlement with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.

FERC REGULATORY MATTERS

Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions.

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Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.

FERC Audit

FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $64 million of costs have been recovered as of June 30, 2024. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Electric Companies are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. If FirstEnergy is unable to recover these transmission or distribution costs, it could result in future charges and/or adjustments and have an adverse impact on FirstEnergy’s financial condition.

ATSI ROE – Ohio Consumers Counsel v. ATSI, et al.

On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.

Transmission ROE Methodology

A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the

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supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis.

Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.

On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.

10. COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications, which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.

As of June 30, 2024, outstanding guarantees and other assurances aggregated $955 million, consisting of parental guarantees on behalf of its consolidated subsidiaries ($516 million) and other assurances ($439 million).

COLLATERAL AND CONTINGENT-RELATED FEATURES

In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

As of June 30, 2024, $135 million of collateral has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $34 million of net cash collateral as of June 30, 2024, from certain generation suppliers, and such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.

These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2024:

Potential Collateral Obligations		Electric Companies and Transmission Companies		FE		Total
	(In millions)
Contractual obligations for additional collateral
Upon further downgrade		$	82	$	1	$	83
Surety bonds (collateralized amount)(1)		97		79		176
Total Exposure from Contractual Obligations		$	179	$	80	$	259

(1) Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.

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ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.

CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.

Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the U.S. Supreme Court. Oral argument was heard on February 21, 2024. On June 27, 2024, the U.S. Supreme Court granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit.

Climate Change

In March 2024, the SEC issued final rules to require public companies to disclose certain climate-related information in registration statements and annual reports filed with the SEC. As adopted, the final climate disclosure rules mandate the disclosure of climate-related risks and the material impacts that severe weather events and other natural conditions have had, or are reasonably likely to have, on FirstEnergy, as well as disclosures related to management and FE Board oversight of such risks. In April 2024, the SEC voluntarily stayed the final climate disclosure rules pending resolution of legal challenges. FirstEnergy currently is assessing the impact of the final climate disclosure rules on its business. There are several initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

As part of its climate strategy, FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). With respect to our coal-fired plants in West Virginia,

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which serve as the primary source of our Scope 1 emissions, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. FirstEnergy cannot currently estimate the financial impact of climate change policies, including the final SEC rules, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule. Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft. Martin and Harrison power stations.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the 5th and 8th Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the Rule pending disposition on the merits. Depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.

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Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of June 30, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. AE Supply continues to evaluate closure options for McElroy’s Run, including the potential transfer of the site and remediation obligations to a third-party, as well as other interpretation changes to its closure plans. As a result, during the second quarter of 2024, AE Supply reviewed its ARO and future expected costs to remediate McElroy’s Run and the adjacent dry landfill, resulting in an increase to the ARO liability and corresponding increase to Other Operating expense of $87 million, which is further described above in Note 8, “Asset Retirement Obligations.” AE Supply continues to evaluate closure options for McElroy’s Run.

On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. Depending on the outcome of appeals and the ultimate implementation of the final rule, compliance with these standards could require remedial actions, including removal of coal ash. See Note 8, “Asset Retirement Obligations,” above for a description of the $125 million increase to its ARO FirstEnergy recorded during the second quarter of 2024 as a result of its analysis.

FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of June 30, 2024 based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $96 million have been accrued through June 30, 2024, of which approximately $69 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

United States v. Larry Householder, et al.

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the U.S Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.

On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public

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statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 21, 2024, FirstEnergy has successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S Attorney’s Office. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information.

Legal Proceedings Relating to United States v. Larry Householder, et al.

On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers relating to the conduct described in the DPA. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. FirstEnergy has cooperated fully with the SEC investigation. FE is working to finalize an agreement-in-principle with the staff of the SEC based upon facts set forth in the DPA that would fully resolve the investigation, which proposed settlement remains subject to approval of the SEC. FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation, and in the second quarter of 2024, a loss contingency of $100 million was recorded and included in “Other Operating expenses” on the Consolidated Statements of Income at Corporate/Other for segment reporting.

On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the, now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and finalize an appropriate resolution of the investigation with respect to FE, which is expected to include a non-prosecution agreement. FE believes that it is probable that it will incur a loss in connection with the resolution of this matter and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp., noted below and, in the second quarter of 2024, a loss contingency of $19.5 million was recorded and included in “Other Operating expenses” on the Consolidated Statements of Income at Corporate/Other for segment reporting.

In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order; the Sixth Circuit granted FE’s petition on November 16, 2023, and conducted oral argument on July 17, 2024. On November 30, 2023, FE filed a motion with the S.D. Ohio to stay all proceedings pending the circuit court appeal. All discovery is stayed during the pendency of the district court motion. FE believes that it is probable that it will

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incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

•MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio); on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. All discovery is stayed during the pendency of the district court motion in In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills will include new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the case in light of the February 9, 2024, indictments against defendants in this action, which the court granted on March 14, 2024. In connection with the ongoing OOCIC resolution discussions, FE is also discussing an appropriate settlement of this civil action with the OAG. FE believes that it is probable that it will incur a loss in connection with the resolution of this matter and the ongoing OOCIC investigation and, as noted above, in the second quarter of 2024, a loss contingency of $19.5 million was recorded.

On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:

•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.

•Miller v. Anderson, et al. (N.D. Ohio); on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon the approval of the settlement by the S.D. Ohio, which was granted on May 17, 2024.

•Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); on September 1, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022, which was appealed by a purported FE stockholder on June 15, 2023. The U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. All appeal options were exhausted on May 16, 2024.

The above settlement included a series of corporate governance enhancements and a payment to FE of $180 million, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs, and a $7 million net return on deposited funds, which was received in the second quarter of 2024. The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.

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The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 9, “Regulatory Matters.”

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations, and cash flows.

11. SEGMENT INFORMATION

On January 1, 2024, FirstEnergy changed its reportable segments as follows, and continues to evaluate segment performance based on earnings attributable to FE:

•Distribution Segment, which consists of the Ohio Companies and FE PA;

•Integrated Segment, which consists of MP, PE and JCP&L; and

•Stand-Alone Transmission Segment, which consists of FE's ownership in FET and KATCo.

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission.

The segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. In accordance with GAAP, the modification to the segments in the first quarter of 2024 resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments for 2023 have been reclassified to conform to the current presentation reflecting the new reportable segments.

The Distribution segment, which consists of the Ohio Companies and FE PA, representing $10.9 billion in 2023 rate base, distributes electricity through FirstEnergy’s electric operating companies in Ohio and Pennsylvania. The Distribution segment serves approximately 4.2 million customers in Ohio and Pennsylvania across its distribution footprint and purchases power for its provider of last resort, SOS, standard service offer and default service requirements. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.

The Integrated segment includes the distribution and transmission operations under JCP&L, MP and PE, as well as MP’s regulated generation operations, representing $8.7 billion in 2023 rate base. The Integrated segment distributes electricity to approximately two million customers in New Jersey, West Virginia and Maryland across its distribution footprint; provides transmission infrastructure in New Jersey, West Virginia, Maryland and Virginia to transmit electricity and operates 3,599 MWs of regulated net maximum capacity located primarily in West Virginia and Virginia. The segment will also include MP and PE’s 50 MWs of solar generation at five sites in West Virginia once complete. The first solar generation site, located in Maidsville, West Virginia, was completed and placed in-service on January 8, 2024, representing 19 MWs of net maximum capacity. Construction of the remaining four sites is expected to be completed no later than the end of 2025. The remaining four sites are expected to provide 31 MWs of net maximum capacity.

The Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, representing $7.7 billion in 2023 rate base, includes transmission infrastructure owned and operated by the Transmission Companies and used to transmit electricity. The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains in the Stand-Alone Transmission segment. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and for comparability, prior year results in the Stand-Alone Transmission segment reflects the earnings and results of those WP transmission assets.

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Corporate/Other reflects corporate support and other costs not charged or attributable to the Electric Companies or Transmission Companies, including FE’s retained pension and OPEB assets and liabilities of former subsidiaries, interest expense on FE’s holding company debt and other investments or businesses that do not constitute an operating segment, including FEV’s investment of 33-1/3% equity ownership in Global Holding. Reconciling adjustments for the elimination of inter-segment transactions are shown separately in the following table of Segment Financial Information. Also included in Corporate/Other for segment reporting is 67 MWs of net maximum capacity, representing AE Supply’s OVEC capacity entitlement. As of June 30, 2024, Corporate/Other had approximately $6.3 billion of FE’s holding company debt.

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Financial information for FirstEnergy’s reportable segments and reconciliations to consolidated amounts is presented below:

(In millions) For the Three Months Ended	Distribution		Integrated		Stand-Alone Transmission		Total Reportable Segments		Corporate/ Other		Reconciling Adjustments		FirstEnergy Consolidated
June 30, 2024
External revenues	$	1,640	$	1,176	$	463	$	3,279	$	1	$	—	$	3,280
Internal revenues	8		2		5		15		—		(15)		—
Total revenues	$	1,648	$	1,178	$	468	$	3,294	$	1	$	(15)	$	3,280
Depreciation	162		132		84		378		19		—		397
Deferral of regulatory assets, net	(9)		—		1		(8)		—		—		(8)
Equity method investment earnings	—		—		—		—		22		—		22
Interest expense	109		65		66		240		84		(39)		285
Income taxes (benefits)	21		36		41		98		(33)		—		65
Earnings (loss) attributable to FE	68		108		81		257		(212)		—		45
Cash Flows from Investing Activities:
Capital investments	$	254	$	350	$	318	$	922	$	20	$	—	$	942
June 30, 2023
External revenues	$	1,616	$	955	$	432	$	3,003	$	3	$	—	$	3,006
Internal revenues	11		1		4		16		—		(16)		—
Total revenues	$	1,627	$	956	$	436	$	3,019	$	3	$	(16)	$	3,006
Depreciation	156		114		74		344		17		—		361
Amortization (deferral) of regulatory assets, net	(9)		(28)		4		(33)		—		—		(33)
Equity method investment earnings	—		—		—		—		35		—		35
Interest expense	96		61		59		216		84		(24)		276
Income taxes (benefits)	32		11		36		79		(5)		—		74
Earnings (losses) attributable to FE	145		75		105		325		(90)		—		235
Cash Flows from Investing Activities:
Capital investments	$	236	$	275	$	246	$	757	$	12	$	—	$	769
For the Six Months Ended
June 30, 2024
External revenues	$	3,396	$	2,270	$	897	$	6,563	$	4	$	—	$	6,567
Internal revenues	19		3		9		31		—		(31)		—
Total revenues	$	3,415	$	2,273	$	906	$	6,594	$	4	$	(31)	$	6,567
Depreciation	323		254		165		742		36		—		778
Amortization (deferral) of regulatory assets, net	(97)		(78)		3		(172)		—		—		(172)
Equity method investment earnings	—		—		—		—		43		—		43
Interest expense	225		136		131		492		201		(103)		590
Income taxes (benefits)	62		71		101		234		(34)		—		200
Earnings (losses) attributable to FE	$	233	$	190	$	165	$	588	$	(290)	$	—	$	298
Cash Flows from Investing Activities:
Capital investments	$	469	$	663	$	576	$	1,708	$	24	$	—	$	1,732
June 30, 2023
External revenues	$	3,423	$	1,981	$	828	$	6,232	$	5	$	—	$	6,237
Internal revenues	21		3		8		32		—		(32)		—
Total revenues	$	3,444	$	1,984	$	836	$	6,264	$	5	$	(32)	$	6,237
Depreciation	309		227		149		685		37		—		722
Amortization (deferral) of regulatory assets, net	(50)		(68)		5		(113)		—		—		(113)
Equity method investment earnings	—		—		—		—		91		—		91
Interest expense	190		120		117		427		161		(49)		539

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Income taxes (benefits)	76		31		69		176		(12)		—		164
Earnings (losses) attributable to FE	$	331	$	145	$	201	$	677	$	(150)	$	—	$	527
Cash Flows from Investing Activities:
Capital investments	$	429	$	512	$	458	$	1,399	$	19	$	—	$	1,418
As of June 30, 2024
Total assets	$	19,736	$	17,815	$	12,634	$	50,185	$	2,716	$	(1,880)	$	51,021
Total goodwill(1)	$	3,222	$	1,953	$	443	$	5,618	$	—	$	—	$	5,618
As of December 31, 2023
Total assets	$	19,235	$	17,466	$	12,142	$	48,843	$	2,372	$	(2,448)	$	48,767
Total goodwill(1)	$	3,222	$	1,953	$	443	$	5,618	$	—	$	—	$	5,618

(1) In accordance with GAAP, the modification to the segments in the first quarter of 2024, as discussed above, resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments.

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ITEM 2.        Management’s Discussion and Analysis of Financial Condition and Results of Operations

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY AND RECENT DEVELOPMENTS

Company Overview

FirstEnergy is dedicated to integrity, safety, reliability and operational excellence and is principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission. Its electric distribution companies form one of the nation's largest investor-owned electric systems, serving over six million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. FirstEnergy’s transmission subsidiaries operate more than 24,000 miles of transmission lines that connect the Midwest and Mid-Atlantic regions and two regional transmission operation centers. AGC and MP control 3,599 MWs of net maximum capacity.

PA Consolidation

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. FE PA serves an area with a population of approximately 4.5 million and operates under the rate districts of the former Pennsylvania Companies. FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.

Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.

Segment Change

During the first quarter of 2024, FirstEnergy’s segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. FirstEnergy’s reportable segments are as follows:

The Distribution segment, which consists of the Ohio Companies and FE PA, representing $10.9 billion in 2023 rate base, distributes electricity through FirstEnergy’s electric operating companies in Ohio and Pennsylvania. The Distribution segment serves approximately 4.2 million customers in Ohio and Pennsylvania across its distribution footprint and purchases power for its provider of last resort, SOS, standard service offer and default service requirements. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.

The Integrated segment includes the distribution and transmission operations under JCP&L, MP and PE, as well as MP’s regulated generation operations, representing $8.7 billion in 2023 rate base. The Integrated segment distributes electricity to approximately two million customers in New Jersey, West Virginia and Maryland across its distribution footprint; provides transmission infrastructure in New Jersey, West Virginia, Maryland and Virginia to transmit electricity and operates 3,599 MWs of regulated net maximum capacity located primarily in West Virginia and Virginia. The segment will also include MP and PE’s 50 MWs of solar generation at five sites in West Virginia once complete. The first solar generation site, located in Maidsville, West Virginia, was completed and placed in-service on January 8, 2024, representing 19 MWs of net maximum capacity. Construction of the remaining four sites is expected to be completed no later than the end of 2025. The remaining four sites are expected to provide 31 MWs of net maximum capacity.

The Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, representing $7.7 billion in 2023 rate base, includes transmission infrastructure owned and operated by the Transmission Companies and used to transmit electricity. The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.

Corporate/Other reflects corporate support and other costs not charged or attributable to the Electric Companies or Transmission Companies, including FE’s retained pension and OPEB assets and liabilities of former subsidiaries, interest expense on FE’s holding company debt and other investments or businesses that do not constitute an operating segment, including FEV’s investment of 33-1/3% equity ownership in Global Holding. Additionally, reconciling adjustments for the

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elimination of inter-segment transactions are included in Corporate/Other. Also included in Corporate/Other for segment reporting is 67 MWs of net maximum capacity, representing AE Supply’s OVEC capacity entitlement. As of June 30, 2024, Corporate/Other had approximately $6.3 billion of FE’s holding company debt.

FirstEnergy believes that this segment reporting serves to provide:

•Greater transparency into our business unit performance;

•Alignment with our cash flow, credit metrics, balance sheet and earnings to the companies comprising each segment;

•Simplification of our segment reporting so that each entire entity resides within a segment; and

•Consistency with peers.

FET Equity Interest Sale

On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes. Interest income associated with the promissory notes was $20 million and $21 million for the three and six months ended June 30, 2024, respectively, and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.

Asset Retirement Obligations

On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR rule requirements for groundwater monitoring and protection procedures, operational and reporting procedures as well as closure requirements for impoundments and landfills that were not originally included for coverage by the 2015 CCR rule. In anticipation of such expenditures, FirstEnergy performed a preliminary assessment of former CCR disposal sites and calculated an initial estimate applying historical experience in remediating comparable sites. As a result, FirstEnergy recorded a $125 million increase to its ARO during the second quarter of 2024, of which $120 million is included in “Other operating expenses” on the Consolidated Statements of Income and was not capitalized as an asset retirement cost since the associated plants do not have future cash flows. In addition, AE Supply continues to evaluate closure options for McElroy’s Run, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of June 30, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. AE Supply continues to evaluate closure options for McElroy’s Run, including the transfer of the site and remediation obligations to a third-party, as well as other interpretation changes to its closure plans. As a result, during the second quarter of 2024, AE Supply reviewed its ARO and future expected costs to remediate McElroy’s Run, resulting in an increase to the ARO liability and corresponding increase to Other operating expense of $87 million.

Our Strategy

Powered by its employees and guided by its experienced leadership team and engaged FE Board, FirstEnergy is accelerating its transformation into a premier electric company. The FE Board and FirstEnergy’s executive management team are aligned behind a business model grounded in investing, operating, recovering costs and financing our regulated electric company operations. This business model aims to create a “virtuous cycle” that in turn serves to improve reliability and the customer experience, grow rate base, engage employees, improve returns and maintain a strong balance sheet. Along with an unwavering commitment to ethics and integrity, performance excellence and continuous improvement, FirstEnergy anticipates that strong execution of this model will help achieve its strategic objectives and deliver value to its investors.

With a diversified asset mix, improved balance sheet and a strong affordability position, FirstEnergy is well positioned to significantly enhance the customer experience and provide value to its investors.

Invest

FirstEnergy invests in its regulated operations to improve reliability and the customer experience, and in its people to attract, retain and develop talented, diverse and engaged employees to carry out its mission. It aims to do so through Energize365.

A robust plan for customer-focused growth, Energize365 is the centerpiece of FirstEnergy’s regulated distribution and transmission capital investment strategy that aims to utilize all investments to support our EESG and strategic priorities including clean energy, improving grid reliability and resiliency, and supports the clean energy transition. Through the Energize365 program, FirstEnergy expects to spend approximately $26 billion in system-wide capital investments from 2024 through 2028.

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FirstEnergy expects that these investments will comprise the Distribution segment (29%), the Integrated segment (39%), and the Stand-Alone Transmission segment (32%), focusing on the following:

•Energy Transition: FirstEnergy expects to make Distribution and Transmission investments in order to support improvements in grid reliability and resiliency and support interconnection of renewable sources, including through:

▪Clean Energy: West Virginia solar generation, energy efficiency, electric vehicle infrastructure and energy storage;

▪Grid Modernization: Programs to drive system resiliency through automation technology and communication, including Ohio's phases one and two of the Ohio Companies’ distribution grid modernization plans, Pennsylvania's LTIIP, New Jersey's EnergizeNJ, and implementing advanced metering infrastructure.

▪Transmission:

•Operational Flexibility Projects that build capacity and support the evolving grid such as interconnection of New Jersey offshore wind and data center load;

•Enhance system performance by implementing new designs and technologies to reduce load at risk; and

•Upgrade system conditions that enhance reliability.

•Infrastructure Renewal: Base distribution projects to address aging infrastructure.

•Generation Maintenance: Projects to maintain operations of fossil fuel plants and remain compliant with environmental regulations through the end of their useful life.

•FirstEnergy believes there is a continued long-term pipeline of investment opportunities for its existing distribution and transmission infrastructure beyond those identified through 2028, which are expected to strengthen grid and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

•Revitalizing its leadership team. During the second quarter of 2024, FirstEnergy appointed four executives to oversee the Ohio, Pennsylvania, New Jersey and Transmission operations. FirstEnergy anticipates naming an executive to oversee its combined West Virginia and Maryland operations in the near term. FirstEnergy continues to make progress in filling several key executive positions in an organization that will be structured to allow greater execution at the business unit level.

Operate

FirstEnergy will continue to engage its skilled, trained, talented and diverse team of employees to effectively implement its investment plans, seek opportunities for continuous improvement as it delivers safe, reliable and affordable electricity to our customers, and deliver value to its investors. It aims to do so through the following:

•Enhancing the focus on the customer. FirstEnergy is shifting more decision-making and accountability for our operations closer to our customers, regulators and employees doing the work. FirstEnergy’s new operating structure is organized by: Ohio, Pennsylvania, New Jersey, West Virginia/Maryland and FirstEnergy’s standalone Transmission properties. This structure will foster better execution at the business unit level.

•Embracing a continuous improvement mindset. FirstEnergy faced numerous financial headwinds in 2023, including weather and the impact of market conditions on its pension plan. Through a determined effort by its employees, FirstEnergy focused on the things within its control: managing costs, enhancing the customer experience and seeking opportunities for continuous improvement.

Recover

FirstEnergy is working to establish a track record of strong execution. Operating effectively leads to strong, predictable results and enhances credibility with our stakeholders. In turn, FirstEnergy builds supportive relationships with regulators, customers and intervenors in an effort to drive positive rate outcomes that support recovery of its investments.

In order to achieve important regulatory milestones, FirstEnergy has an active regulatory calendar to support its regulated growth strategy and address the critical investments that support reliability and a smarter and cleaner electric grid. This includes the following:

•On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. On August 22, 2023, the parties filed a unanimous settlement of the case recommending a $33 million annual increase in depreciation expense, effective April 1, 2024, but deferred issues related to a change in the net energy metering credit. An order was issued on March 26, 2024 approving the settlement without modification.

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•On March 16, 2023, JCP&L filed a base rate case in New Jersey, requesting a $185 million increase in base distribution revenues to support investments to strengthen the energy grid, enhance the customer experience and provide assistance to low-income and senior citizen customers. February 1, 2024, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s request for a distribution base rate increase. The settlement, which was approved by the NJBPU on February 14, 2024, provides for an $85 million annual base distribution revenue increase for JCP&L, which became effective for customers on June 1, 2024.

•On April 5, 2023, the Ohio Companies sought approval from the PUCO for its ESP V. The proposed plan would maintain an eight-year term beginning June 1, 2024, and seeks to continue riders recovering costs associated with distribution infrastructure investments and approved grid modernization investments. ESP V additionally proposes new riders that would support reliability, and includes provisions supporting affordability and enhancing the customer experience. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which are described below in “Outlook - State Regulation - Ohio”. On June 14, 2024, the Ohio Companies filed an Application for Rehearing, which is pending before the PUCO.

•On December 1, 2023, JCP&L filed a petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and has a proposed budget of approximately $964 million. Public hearings were held on June 11, 2024, and the parties are currently engaged in settlement discussions. On July 1, 2024, the NJBPU suspended the procedural schedule. A final NJBPU decision and order is required no later than October 15, 2024.

•On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, as amended, if approved will result in the investment of approximately $930.5 million of total estimated costs over five years.

•On April 2, 2024, FE PA filed a base rate case with the PPUC seeking a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act, and smart meter. Additionally, FE PA requests an enhanced ten year vegetation management program and recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025.

•On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the next phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period beginning January 1, 2025 and ending December 31, 2029.

•On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. Evidentiary hearings began on June 5, 2024 and concluded on July 2, 2024.

•On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates, based on a 2024 calendar year test period ending May 31, 2024. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, and reflects a roll-in of current riders such as DCR and AMI. The net increase represents a 1.5% average residential monthly bill increase. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony and expect by month-end to file an update with an adjusted net increase of base distribution revenues and incorporating matters in the rate case as directed by the PUCO’s ESP V Order.

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Finance

With sound capital allocation, enhanced reliability and better regulatory outcomes, FirstEnergy represents a compelling investment and expects to finance the business at a lower cost of capital, allowing it to begin the virtuous cycle all over again at “Invest.”

FirstEnergy aims to do this through a strengthened financial position. Since 2021, FirstEnergy has raised $7 billion in equity capital and issued $1.5 billion in convertible notes in May 2023 to significantly improve its balance sheet. The strength of FirstEnergy’s balance sheet supports its plan to fund Energize365 investments through organic internal cash flows and electric company debt rather than incremental equity. FirstEnergy has also de-levered risk associated with its pension plan and optimized its financing plan to retain flexibility in an uncertain interest rate environment.

FirstEnergy also expects to continue returning value to shareholders. In March 2024, the FE Board declared a $0.015 per share increase to the quarterly common stock dividend payable June 1, 2024, to $0.425 per share, which represents an approximate 6% increase compared to dividends declared in 2023. Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings growth, credit metrics and other business conditions.

Climate Strategy

Our commitment to climate is a significant component of our company’s overarching strategy, especially our desire to help enable the transition to a clean energy future. Executing our Climate Strategy requires addressing, among other things: emerging federal and state decarbonization goals; physical risks of climate change; industry trends and technology advancements; and customer expectations for cleaner energy, increased usage control, and more sustainable alternatives in transportation, manufacturing and industrial processes. Through our investment plan, we aim to enhance the resiliency, reliability and security of the electric system and support the integration of renewables, electric vehicles, grid modernization improvements and other emerging technologies.

As part of our Climate Strategy, we are committed to addressing company-wide emissions within our direct operational control, also known as Scope 1 emissions, across our transmission, distribution and regulated generation operations. With the climate, our business, and our stakeholders in mind, our Climate Strategy is two-fold:

•Reduce our company’s Scope 1 GHG emissions and achieve carbon neutrality by 2050; and

•Support broader GHG reductions in our region by helping to enable the energy transition to a low-carbon future.

Currently, emissions from our West Virginia power stations – Fort Martin and Harrison – serve as the primary source of our Scope 1 emissions – representing approximately 99% of our overall GHG emissions as of December 31, 2023 – and greatly outnumber the emissions from our transmission and distribution operations. We have publicly stated through various filings with the WVPSC that the end of useful life date is 2035 for Fort Martin and 2040 for Harrison. These dates are based on our assessment of when it is projected to no longer be cost effective and beneficial to customers to make the capital investments needed to keep these facilities operating effectively and in compliance with evolving environmental regulations, and are subject to our ongoing evaluation of recently-finalized EPA rules relating to CCR regulations that are discussed elsewhere in this Form 10-Q. In 2025, FirstEnergy plans to submit an Integrated Resource Plan to the WVPSC that will include our analysis of market conditions and identify how we believe we can best fulfill our obligation to supply our generation customers with reliable and cost-effective energy through 2040 (a requirement every five years in the state of West Virginia).

In the near-term, we continue our focus on GHG reduction in our transmission and distribution businesses. These emissions are within our control, pervasive in every state across our footprint, and aligned with our long-term, forward-looking transmission and distribution strategy to enable the energy transition.

In addition to moving beyond our two coal-fired West Virginia power stations, key steps in working toward carbon neutrality by 2050 include:

•Reducing sulfur hexafluoride emissions: We are working to repair or replace, as appropriate, transmission breakers that leak sulfur hexafluoride, which is a gas commonly used by energy companies as an electrical insulating material and arc extinguisher in high-voltage circuit breakers and switchgear. If escaped to the atmosphere, it acts as a potent GHG with a global warming potential significantly greater than CO2; and

•Electrifying our vehicle fleet: We are targeting 30% electrification of our light-duty and aerial truck fleet by 2030 and 100% electrification by 2050. To reach our electrification goal, we are striving for 100% electric or hybrid vehicle purchases for our light-duty and aerial truck fleet moving forward.

Determination of the useful life of the regulated coal-fired generating facilities could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations and cash flow.

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HB 6 and Related Investigations

On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the U.S. Attorney’s Office investigation into FirstEnergy relating to FirstEnergy’s lobbying and governmental affairs activities concerning HB 6 related to the federal criminal allegations made in July 2020, against former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Among other things under the DPA, FE paid a $230 million monetary penalty in 2021 and agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. As of July 21, 2024, FirstEnergy has successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S. Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information.

The OAG, certain FE shareholders and FE customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve multiple shareholder derivative lawsuits that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which was granted on May 9, 2022. On August 23, 2022, the S.D. Ohio granted final approval of the settlement. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022, and the S.D. Ohio denied that motion on May 22, 2023. On June 15, 2023, the purported FE stockholder filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. The N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. All appeal options were exhausted on May 16, 2024, and the judgment and settlement became final, resolving the derivative lawsuits. On May 17, 2024, the N.D. Ohio granted the parties’ motion to dismiss based upon the approval of the settlement by the S.D. Ohio. The state court action was also dismissed on September 2, 2022.

The above settlement included a series of corporate governance enhancements and a payment to FE of $180 million, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs, and a $7 million net return on deposited funds, which was received in the second quarter of 2024. The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.

On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers relating to the conduct described in the DPA. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. FirstEnergy has cooperated fully with the SEC investigation. FE is working to finalize an agreement-in-principle with the staff of the SEC based upon facts set forth in the DPA that would fully resolve the investigation, which proposed settlement remains subject to approval of the SEC. FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation, and in the second quarter of 2024, a loss contingency of $100 million was recorded and included in “Other Operating expenses” on the Consolidated Statements of Income at Corporate/Other for segment reporting.

On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the, now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and finalize an appropriate resolution of the investigation with respect to FE, which is expected to include a non-prosecution agreement. FE believes that it is probable that it will incur a loss in connection with the resolution of this matter and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp., and, in the second quarter of 2024, a loss contingency of $19.5 million was recorded and included in “Other Operating expenses” on the Consolidated Statements of Income at Corporate/Other for segment reporting.

FirstEnergy has taken numerous steps to address challenges posed by the HB 6 investigations and improve its compliance culture, including the refreshment of the FE Board, the hiring of key senior executives committed to supporting transparency and

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integrity, and strengthening and enhancing FirstEnergy’s compliance culture through several initiatives; however, the outcomes of the unresolved HB 6 investigations and state regulatory audits remain unknown.

Despite the many disruptions FirstEnergy has faced, and continues to currently face, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigations, the DPA, and ongoing litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FirstEnergy’s financial condition, results of operations and cash flows.

FIRSTENERGY’S CONSOLIDATED RESULTS OF OPERATIONS

Second Quarter of 2024 Compared with Second Quarter of 2023

(In millions)	For the Three Months Ended June 30,
	2024		2023		Increase (Decrease)
Revenues	$	3,280	$	3,006	$	274	9	%
Operating expenses	(2,857)		(2,525)		332		13	%
Other expenses, net	(260)		(153)		107		70	%
Income taxes	(65)		(74)		(9)		(12)	%
Income attributable to noncontrolling interest	(53)		(19)		34		179	%
Earnings attributable to FE	$	45	$	235	$	(190)	(81)	%

Earnings attributable to FE was $45 million or $0.08 per share (basic and diluted) in the second quarter of 2024 compared to $235 million or $0.41 per share (basic and diluted) in the second quarter of 2023, a decrease of $190 million that was primarily due to the following:

•Charges related to changes in ARO liabilities associated with final CCR rules and changes in future expected costs to remediate McElroy’s Run;

•Loss contingencies associated with the SEC and OOCIC investigations as further discussed below in “Outlook - Other Legal Proceedings”;

•Higher other operating expenses as described below;

•The dilutive effect of the 30% additional minority equity interest sale in FET that closed in March 2024;

•Lower investment earnings related to FEV’s equity method investment in Global Holding;

•The absence of the pension mark-to-market adjustment; and

•Higher debt redemption costs and interest on short-term borrowings.

These factors were partially offset by the following:

•Proceeds from the shareholder derivative lawsuit settlement as described below in “Outlook - Other Legal Proceedings”;

•The implementation of base rate case settlements in Maryland, New Jersey and West Virginia;

•Higher customer usage and demand;

•Higher transmission rate base;

•The absence of benefit costs associated with the PEER program and involuntary separations that occurred in the second quarter of 2023; and

•Lower interest expense from long-term debt redemptions.

Detailed segment reporting explanations are included below.

Distribution services by customer class are summarized in the following table:

	For the Three Months Ended June 30,
(In thousands)	Actual				Weather-Adjusted
Electric Distribution MWh Deliveries	2024	2023	Increase (Decrease)		2024	2023	Increase (Decrease)
Residential	12,536	10,836	15.7	%	11,989	11,511	4.2	%
Commercial(1)	9,126	8,160	11.8	%	8,963	8,362	7.2	%
Industrial	13,820	13,885	(0.5)	%	13,820	13,885	(0.5)	%
Total Electric Distribution MWh Deliveries	35,482	32,881	7.9	%	34,772	33,758	3.0	%

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(1) Includes street lighting.

Residential and commercial distribution deliveries were impacted by higher customer usage as a result of the weather. Cooling degree days in the second quarter of 2024 were 131% above the same period of 2023 and 37% above normal. Heating degree days in the second quarter of 2024 were 23% below the same period of 2023 and 28% below normal.

First Six Months of 2024 Compared with First Six Months of 2023

(In millions)	For the Six Months Ended June 30,
	2024		2023		Increase (Decrease)
Revenues	6,567		6,237		$	330	5	%
Operating expenses	(5,532)		(5,205)		327		6	%
Other expenses, net	(470)		(304)		166		55	%
Income taxes	(200)		(164)		36		22	%
Income attributable to noncontrolling interest	(67)		(37)		30		81	%
Earnings attributable to FE	$	298	$	527	$	(229)	(43)	%

Earnings attributable to FE was $298 million or $0.52 per share (basic and diluted) in the second quarter of 2024 compared to $527 million or $0.92 per share (basic and diluted) in the second quarter of 2023, a decrease of $229 million that was primarily due to the following:

•Charges related to changes in ARO liabilities associated with final CCR rules and changes in future expected costs to remediate McElroy’s Run;

•Loss contingencies associated with the SEC and OOCIC investigations as further discussed below in “Outlook - Other Legal Proceedings”;

•Higher other operating expenses as described below;

•Lower investment earnings related to FEV’s equity method investment in Global Holding;

•The absence of the pension mark-to-market adjustment;

•The dilutive effect of the 30% additional minority equity interest sale in FET that closed in March 2024;

•Higher net interest expenses and debt redemption costs; and

•Higher net discrete income tax charges related to the PA Consolidation and updates to deferred taxes on the sale of equity interest in FET in the first quarter of 2024, partially offset by discrete benefits primarily associated with state NOL utilization.

These were partially offset by the following:

•Proceeds from the shareholder derivative lawsuit settlement as described below in “Outlook - Other Legal Proceedings”;

•The implementation of base rate case settlements in Maryland, New Jersey and West Virginia;

•Higher customer usage and demand;

•Higher transmission rate base;

•The absence of expenses associated with the cancellation of a sponsorship agreement in the first quarter of 2023;

•The absence of the pension mark-to-market adjustment; and

•The absence of benefit costs associated with the PEER program and involuntary separations that occurred in the second quarter of 2023.

Detailed segment reporting explanations are included below.

Distribution services by customer class are summarized in the following table:

	For the Six Months Ended June 30,
(In thousands)	Actual				Weather-Adjusted
Electric Distribution MWh Deliveries	2024	2023	Increase		2024	2023	Increase (Decrease)
Residential	26,623	24,776	7.5	%	27,417	27,493	(0.3)	%
Commercial(1)	17,741	16,793	5.6	%	17,931	17,765	0.9	%
Industrial	27,744	27,396	1.3	%	27,744	27,396	1.3	%
Total Electric Distribution MWh Deliveries	72,108	68,965	4.6	%	73,092	72,654	0.6	%

(1) Includes street lighting.

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Residential and commercial distribution deliveries were impacted by higher customer usage as a result of the weather. Cooling degree days in the first six months of 2024 were 131% above the same period of 2023 and 37% above normal. Heating degree days in the first six months of 2024 were flat to the same period of 2023 and 17% below normal.

The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 11, “Segment Information,” of the Notes to Consolidated Financial Statements.

Summary of Results of Operations — Second Quarter 2024 Compared with Second Quarter 2023

Financial results for FirstEnergy’s business segments for the second quarter of 2024 and 2023 were as follows:

Second Quarter 2024 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	1,610	$	1,162	$	463	$	1	$	3,236
Other	38		16		5		(15)		44
Total Revenues	1,648		1,178		468		(14)		3,280
Operating Expenses:
Fuel	—		128		—		—		128
Purchased power	510		363		—		4		877
Other operating expenses	640		338		91		101		1,170
Provision for depreciation	162		132		84		19		397
Amortization (deferral) of regulatory assets, net	(9)		—		1		—		(8)
General taxes	181		32		70		10		293
Total Operating Expenses	1,484		993		246		134		2,857
Other Income (Expense):
Debt redemption costs	—		—		—		(85)		(85)
Equity method investment earnings	—		—		—		22		22
Miscellaneous income, net	29		14		5		11		59
Interest expense	(109)		(65)		(66)		(45)		(285)
Capitalized financing costs	5		10		14		—		29
Total Other Expense	(75)		(41)		(47)		(97)		(260)
Income taxes (benefits)	21		36		41		(33)		65
Income attributable to noncontrolling interest	—		—		53		—		53
Earnings (Loss) Attributable to FE	$	68	$	108	$	81	$	(212)	$	45

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Second Quarter 2023 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	1,582	$	940	$	432	$	3	$	2,957
Other	45		16		4		(16)		49
Total Revenues	1,627		956		436		(13)		3,006
Operating Expenses:
Fuel	—		140		—		—		140
Purchased power	566		323		—		5		894
Other operating expenses	532		278		92		(17)		885
Provision for depreciation	156		114		74		17		361
Amortization (deferral) of regulatory assets, net	(9)		(28)		4		—		(33)
General taxes	174		30		65		9		278
Total Operating Expenses	1,419		857		235		14		2,525
Other Income (Expense):
Debt redemption costs	—		—		—		(36)		(36)
Equity method investment earnings	—		—		—		35		35
Miscellaneous income (expense), net	26		16		5		(4)		43
Pension and OPEB mark-to-market adjustment	34		24		6		(5)		59
Interest expense	(96)		(61)		(59)		(60)		(276)
Capitalized financing costs	5		8		7		2		22
Total Other Expense	(31)		(13)		(41)		(68)		(153)
Income taxes (benefits)	32		11		36		(5)		74
Income attributable to noncontrolling interest	—		—		19		—		19
Earnings (Loss) Attributable to FE	$	145	$	75	$	105	$	(90)	$	235

Changes Between Second Quarter 2024 and Second Quarter 2023 Financial Results (In millions)	Distribution		Integrated		Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	28	$	222	$	31	$	(2)	$	279
Other	(7)		—		1		1		(5)
Total Revenues	21		222		32		(1)		274
Operating Expenses:
Fuel	—		(12)		—		—		(12)
Purchased power	(56)		40		—		(1)		(17)
Other operating expenses	108		60		(1)		118		285
Provision for depreciation	6		18		10		2		36
Amortization (deferral) of regulatory assets, net	—		28		(3)		—		25
General taxes	7		2		5		1		15
Total Operating Expenses	65		136		11		120		332
Other Income (Expense):
Debt redemption costs	—		—		—		(49)		(49)
Equity method investment earnings	—		—		—		(13)		(13)
Miscellaneous income (expense), net	3		(2)		—		15		16
Pension and OPEB mark-to-market adjustment	(34)		(24)		(6)		5		(59)
Interest expense	(13)		(4)		(7)		15		(9)
Capitalized financing costs	—		2		7		(2)		7
Total Other Expense	(44)		(28)		(6)		(29)		(107)
Income taxes (benefits)	(11)		25		5		(28)		(9)
Income attributable to noncontrolling interest	—		—		34		—		34
Earnings (Loss) Attributable to FE	$	(77)	$	33	$	(24)	$	(122)	$	(190)

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Distribution Segment — Second Quarter of 2024 Compared with Second Quarter of 2023

Distribution segment’s earnings attributable to FE decreased $77 million in the second quarter of 2024, as compared to the same period of 2023, primarily resulting from higher other operating expenses, including increases in the ARO liability, the absence of the pension mark-to-market adjustment, and higher interest expense, partially offset by higher customer usage and demand, and higher revenues from regulated investment programs.

Revenues —

Distribution’s total revenues increased $21 million as a result of the following sources:

		For the Three Months Ended June 30,
Revenues by Type of Service	2	2024			2023		Increase (Decrease)
		(In millions)
Distribution services		$	1,015	2	$	875	$	140
Generation sales:
Retail		594			696		(102)
Wholesale		1			11		(10)
Total generation sales		595			707		(112)
Other		38			45		(7)
Total Revenues		$	1,648		$	1,627	$	21

Distribution services revenues increased $140 million in the second quarter of 2024, as compared to the same period of 2023, primarily resulting from higher customer usage as a result of the weather, higher weather-adjusted customer usage and demand, higher rider revenues associated with certain investment programs, and lower customer credits associated with the PUCO-approved Ohio Stipulation. Additionally, revenues increased due to the higher recovery of transmission expenses and other rider rate adjustments at FE PA, which have no material impact to earnings.

Generation sales revenues decreased $112 million in the second quarter of 2024, as compared to the same period in 2023, primarily due to lower retail generation sales as a result of increased customer shopping, partially offset by higher non-shopping generation auction rates. Total generation provided by alternative suppliers as a percentage of total MWh deliveries in the second quarter of 2024, as compared to the same period of 2023, increased to 90% from 72% in Ohio and increased to 65% from 64% in Pennsylvania. Retail and wholesale generation sales revenue have no material impact to earnings.

Operating Expenses —

Total operating expenses increased $65 million, primarily due to:

•Purchased power costs, which have no material impact to earnings, decreased $56 million during the second quarter of 2024, as compared to the same period of 2023, primarily due to decreased generation sales volumes of $131 million as described above and decreased capacity expenses of $2 million, partially offset by higher unit costs of $77 million.

•Other operating expenses increased $108 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to:

•Higher network transmission expenses of $39 million, which are deferred for future recovery, resulting in no material impact to earnings;

•$46 million charge related to changes in ARO liabilities associated with final CCR rules;

•$32.5 million contribution commitment by the Ohio Companies as a result of the Ohio ESP V PUCO order, as further discussed below;

•Higher planned vegetation management expenses of $15 million; and

•Higher uncollectible expenses of $29 million, of which $6 million was deferred for future recovery, primarily due to a reduction to the allowance during the second quarter of 2023.

The increase was partially offset by:

•Lower other operating expenses of $25 million, primarily due to lower employee labor and benefits including the absence of benefit costs associated with the PEER program and involuntary separations that occurred in the second quarter of 2023;

•Lower storm expenses of $27 million, the majority of which were deferred for future recovery, resulting in no material impact to earnings; and

•Lower energy efficiency and other state mandated program costs of $2 million, which were deferred for future recovery, resulting in no material impact to earnings.

•Depreciation expense increased $6 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to a higher asset base.

•Deferral of regulatory assets were flat to the second quarter of 2024, as compared to the same period of 2023, primarily due to a $32 million net increase from higher generation and transmission related deferrals, partially offset by a $29 million decrease due to lower deferral of storm related expenses, and $3 million related to net decreases in other deferrals.

•General taxes increased $7 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to higher gross receipts taxes.

Other Expense —

Other expense increased $44 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to the absence of the pension mark-to-market adjustment and higher net interest expense associated with short-term borrowings.

Income Taxes —

Distribution segment’s effective tax rate was 23.6% and 18.1% for the three months ended June 30, 2024 and 2023, respectively. The increase in the effective tax rate was primarily due to the absence of certain state income tax benefits, as well as a reduction in the tax benefit from amortization of excess deferred income taxes.     

Integrated Segment — Second Quarter of 2024 Compared with Second Quarter of 2023

Integrated segment’s earnings attributable to FE increased $33 million in the second quarter of 2024, as compared to the same period of 2023, primarily from the implementation of base rate cases, higher customer usage and demand, partially offset by higher other operating expenses, including increases in the ARO liability, a higher effective tax rate due to discrete tax charges discussed below, and the absence of pension mark-to-market adjustment.

Revenues —

Integrated segment’s total revenues increased $222 million as a result of the following sources:

		For the Three Months Ended June 30,
Revenues by Type of Service	2	2024		2023		Increase (Decrease)
		(In millions)
Distribution services		$	381	$	311	$	70
Generation sales:
Retail		627		493		134
Wholesale		38		50		(12)
Total generation sales		$	665	$	543	$	122
Transmission revenues:
JCP&L		66		57		9
MP & PE		50		29		21
Total transmission revenues		$	116	$	86	$	30
Other		16		16		—
Total Revenues		$	1,178	$	956	$	222

Distribution services revenues increased $70 million in the second quarter of 2024, as compared to the same period of 2023, primarily resulting from higher customer usage as a result of the weather, higher weather-adjusted customer usage and demand, higher revenues from the implementation of base rate cases, and higher rider revenues associated with certain investment programs. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.

Generation sales revenues increased $122 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to higher retail revenues, partially offset by lower wholesale revenues.

•Retail generation sales increased $134 million in the second quarter of 2024, as compared to the same period in 2023 primarily due to higher customer usage as a result of the weather and higher non-shopping generation auction rates. Retail generation sales, other than those in West Virginia, have no material impact to earnings.

•Wholesale generation revenues decreased $12 million in the second quarter of 2024, as compared to the same period in 2023, primarily due to lower capacity revenues and market prices, partially offset by higher sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.

Transmission revenues increased $30 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to higher rate base from regulated investment programs.

Operating Expenses —

Total operating expenses increased $136 million, primarily due to:

•Fuel costs decreased $12 million during the second quarter of 2024, as compared to the same period of 2023, primarily due to lower unit costs, partially offset by higher generation output. Due to the ENEC, fuel expense has no material impact to earnings.

•Purchased power costs, which have no material impact to earnings, increased $40 million during the second quarter of 2024, as compared to the same period of 2023, primarily due to higher unit costs, partially offset by lower sales volumes and lower capacity expenses.

•Other operating expenses increased $60 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to:

•Distribution related other operating expenses increased $65 million primarily due to:

•Higher storm expenses of $30 million, of which $29 million was deferred for future recovery;

•Higher network transmission expenses of $9 million, which were deferred for future recovery, resulting in no material impact to earnings;

•$16 million charge related to changes in ARO liabilities associated with final CCR rules;

•Higher planned vegetation management costs of $6 million, which were deferred for future recovery resulting in no material impact to earnings;

•Higher uncollectible expenses of $10 million, which were deferred for future recovery, primarily due to a reduction to the allowance during the second quarter of 2023;

•Higher energy efficiency and other state mandated program costs of $8 million, which were deferred for future recovery, resulting in no material impact to earnings; and

•Higher regulated generation outage spend of $3 million.

The increase was partially offset by:

•Lower other operating and maintenance expenses of $17 million, primarily due to lower employee labor and benefits, including the absence of benefit costs associated with the PEER program and involuntary separations that occurred in the second quarter of 2023.

•Transmission related other operating expenses decreased $5 million primarily due to lower operating and maintenance expenses. Nearly all transmission related operating expenses are recovered through formula rates, resulting in no material impact to earnings.

•Depreciation expense increased $18 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to a higher asset base.

•Deferral of regulatory assets decreased $28 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to a $63 million net decrease from lower generation and transmission related deferrals, partially offset by a $25 million increase from higher deferral of storm related expenses, and $10 million related to net increases in other deferrals.

•General taxes increased $2 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to higher gross receipts taxes.

Other Expense —

Other expense increased $28 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to the absence of the pension mark-to-market adjustment, higher net interest expense associated with short-term borrowings, and non-recoverable charges related to an abandoned transmission project.

Income Taxes —

Integrated segment’s effective tax rate was 25.0% and 12.8% for the three months ended June 30, 2024 and 2023, respectively. The increase was primarily due to the absence of a benefit recognized in the second quarter of 2023 related to the remeasurement of a valuation allowance for the expected utilization of certain state NOL carryforwards.

Stand-Alone Transmission Segment — Second Quarter of 2024 Compared with Second Quarter of 2023

Stand-Alone Transmission Segment’s earnings attributable to FE decreased $24 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to the dilutive effect of the 30% additional minority equity interest sale in FET that closed in March 2024, higher short-term borrowings and interest rates, partially offset by increased earnings as a result of regulated capital investments that increased rate base.

Revenues —

Stand-Alone Transmission’s total revenues increased $32 million, primarily due to a higher rate base and recovery of higher transmission operating expenses.

The following table shows revenues by transmission asset owner:

		For the Three Months Ended June 30,
Revenues by Transmission Asset Owner	2	2024		2023		Increase (Decrease)
		(In millions)
ATSI		264		243		$	21
TrAIL		72		67		5
MAIT		111		99		12
KATCo		23		27		(4)
Other		(2)		—		(2)
Total Revenues		$	468	$	436	$	32

Operating Expenses —

Total operating expenses increased $11 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to higher depreciation and property tax expenses from a higher asset base. Nearly all operating expenses are recovered through formula rates, resulting in no material impact to earnings.

Other Expense —

Total other expense increased $6 million in the second quarter of 2024, as compared to the same period of 2023, primarily due to higher short-term borrowings and net interest expense due to the new debt issuances and the absence of the pension mark-to-market adjustment, partially offset by higher capitalized financing costs.

Income Taxes —

Stand-Alone Transmission’s effective tax rate was 23.4% and 22.5% for the three months ended June 30, 2024 and 2023, respectively.

Corporate / Other — Second Quarter 2024 Compared with Second Quarter 2023

Financial results at Corporate/Other resulted in a $122 million increase in losses attributable to FE in the second quarter of 2024, as compared to the same period of 2023, primarily due to:

•$120 million in loss contingencies associated with the SEC and OOCIC investigations as further discussed below in “Outlook - Other Legal Proceedings”;

•$115 million (after-tax) charge related to changes in ARO liabilities associated with final CCR rules and McElroy’s Run;

•$15 million (after-tax) of higher debt redemption costs and higher net interest expense associated with the 2026 Convertible Notes issuance in May 2023, partially offset by lower revolver borrowings, and higher interest income related to the FET Equity Interest Sale promissory notes and money pool investments; and

•$11 million (after-tax) in lower investment earnings related to FEV’s equity method investment in Global Holding.

These losses were partially offset by:

•$116 million (after-tax) of proceeds from the shareholder derivative lawsuit settlement as described below in “Outlook - Other Legal Proceedings”;

•$4 million (after-tax) from the absence of the pension mark-to-market adjustment; and

48

•The absence of a $9 million discrete income tax charge recognized in 2023 due to the remeasurement of a valuation allowance for the expected utilization of certain state NOL carryforwards.

49

Summary of Results of Operations — First Six Months of 2024 Compared with First Six Months of 2023

Financial results for FirstEnergy’s business segments for the first six months of 2024 and 2023 were as follows:

First Six Months 2024 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	3,335	$	2,244	$	897	$	4	$	6,480
Other	80		29		9		(31)		87
Total Revenues	3,415		2,273		906		(27)		6,567
Operating Expenses:
Fuel	—		233		—		—		233
Purchased power	1,152		752		—		9		1,913
Other operating expenses	1,227		692		167		90		2,176
Provision for depreciation	323		254		165		36		778
Amortization (deferral) of regulatory assets, net	(97)		(78)		3		—		(172)
General taxes	373		70		139		22		604
Total Operating Expenses	2,978		1,923		474		157		5,532
Other Income (Expense):
Debt redemption costs	—		—		—		(85)		(85)
Equity method investment earnings	—		—		—		43		43
Miscellaneous income (expense), net	73		26		5		(1)		103
Interest expense	(225)		(136)		(131)		(98)		(590)
Capitalized financing costs	10		21		27		1		59
Total Other Expense	(142)		(89)		(99)		(140)		(470)
Income taxes (benefits)	62		71		101		(34)		200
Income attributable to noncontrolling interest	—		—		67		—		67
Earnings (Loss) Attributable to FE	$	233	$	190	$	165	$	(290)	$	298

First Six Months 2023 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	3,361	$	1,952	$	828	$	5	$	6,146
Other	83		32		8		(32)		91
Total Revenues	3,444		1,984		836		(27)		6,237
Operating Expenses:
Fuel	—		273		—		—		273
Purchased power	1,283		725		—		10		2,018
Other operating expenses	1,035		538		163		(5)		1,731
Provision for depreciation	309		227		149		37		722
Amortization (deferral) of regulatory assets, net	(50)		(68)		5		—		(113)
General taxes	362		64		128		20		574
Total Operating Expenses	2,939		1,759		445		62		5,205
Other Income (Expense):
Debt redemption costs	—		—		—		(36)		(36)
Equity method investment earnings	—		—		—		91		91
Miscellaneous income (expense), net	48		32		11		(13)		78
Pension and OPEB mark-to-market adjustment	34		24		6		(5)		59
Interest expense	(190)		(120)		(117)		(112)		(539)
Capitalized financing costs	10		15		16		2		43
Total Other Expense	(98)		(49)		(84)		(73)		(304)
Income taxes (benefits)	76		31		69		(12)		164
Income attributable to noncontrolling interest	—		—		37		—		37
Earnings (Loss) Attributable to FE	$	331	$	145	$	201	$	(150)	$	527

50

Changes Between First Six Months 2024 and First Six Months 2023 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	(26)	$	292	$	69	$	(1)	$	334
Other	(3)		(3)		1		1		(4)
Total Revenues	(29)		289		70		—		330
Operating Expenses:
Fuel	—		(40)		—		—		(40)
Purchased power	(131)		27		—		(1)		(105)
Other operating expenses	192		154		4		95		445
Provision for depreciation	14		27		16		(1)		56
Amortization (deferral) of regulatory assets, net	(47)		(10)		(2)		—		(59)
General taxes	11		6		11		2		30
Total Operating Expenses	39		164		29		95		327
Other Income (Expense):
Debt redemption costs	—		—		—		(49)		(49)
Equity method investment earnings	—		—		—		(48)		(48)
Miscellaneous income (expense), net	25		(6)		(6)		12		25
Pension and OPEB mark-to-market adjustment	(34)		(24)		(6)		5		(59)
Interest expense	(35)		(16)		(14)		14		(51)
Capitalized financing costs	—		6		11		(1)		16
Total Other Expense	(44)		(40)		(15)		(67)		(166)
Income taxes (benefits)	(14)		40		32		(22)		36
Income attributable to noncontrolling interest	—		—		30		—		30
Earnings (Loss) Attributable to FE	$	(98)	$	45	$	(36)	$	(140)	$	(229)

51

Distribution Segment — First Six Months of 2024 Compared with First Six Months of 2023

Distribution segment’s earnings attributable to FE decreased $98 million in the first six months of 2024, as compared to the same period of 2023, primarily resulting from lower weather-adjusted customer usage and demand, and higher other operating expenses, including increases in the ARO liability, partially offset by higher customer usage as a result of the weather and higher revenues from regulated investment programs.

Revenues —

Distribution’s total revenues decreased by $29 million as a result of the following sources:

	For the Six Months Ended June 30,
Revenues by Type of Service	2024		2023		Increase (Decrease)
	(In millions)
Distribution services	$	2,036	$	1,844	$	192
Generation sales:
Retail	1,297		1,504		(207)
Wholesale	2		13		(11)
Total generation sales	1,299		1,517		(218)
Other	80		83		(3)
Total Revenues	$	3,415	$	3,444	$	(29)

Distribution services revenues increased $192 million in the first six months of 2024, as compared to the same period of 2023, primarily resulting from higher customer usage as a result of the weather, higher rider revenues associated with investment programs, and lower customer credits associated with the PUCO-approved Ohio Stipulation. Additionally, revenues increased due to the higher recovery of transmission expenses and other rider rate adjustments at FE PA, which have no material impact to earnings. Higher distribution services revenue were partially offset by lower weather-adjusted customer usage and demand.

Generation sales revenues decreased $218 million in the first six months of 2024, as compared to the same period in 2023, primarily due to lower retail generation sales as a result of increased customer shopping, partially offset by higher non-shopping generation auction rates. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA in the first six months of 2024, as compared to the same period of 2023, increased to 90% from 64% in Ohio and increased to 63% from 62% in Pennsylvania. Retail and wholesale generation sales revenue have no material impact to earnings.

Operating Expenses —

Total operating expenses increased $39 million, primarily due to:

•Purchased power costs, which have no material impact to earnings, decreased $131 million during the first six months of 2024, as compared to the same period of 2023, primarily due to decreased generation sales volumes of $355 million as described above and decreased capacity expenses of $6 million, partially offset by higher unit costs of $230 million.

•Other operating expenses increased $192 million in the first six months of 2024, as compared to the same period of 2023, primarily due to:

•Higher network transmission expenses of $75 million, which are deferred for future recovery, resulting in no material impact to earnings;

•$46 million charge related to changes in ARO liabilities associated with final CCR rules;

•$32.5 million contribution commitment by the Ohio Companies, as a result of the Ohio ESP V PUCO order, as further discussed below;

•Higher planned vegetation management expenses of $31 million;

•Higher energy efficiency and other state mandated program costs of $5 million, which were deferred for future recovery, resulting in no material impact to earnings; and

•Higher uncollectible expenses of $37 million, of which $11 million was deferred for future recovery, primarily due to a reduction to the allowance during the second quarter of 2023.

This increase was partially offset by:

•Lower other operating expenses of $31 million, primarily due to lower employee labor and benefits, including the absence of benefit costs associated with the PEER program and involuntary separations that occurred in the second quarter of 2023; and

•Lower storm expenses of $4 million, which were deferred for future recovery, resulting in no material impact to earnings.

•Depreciation expense increased $14 million in the first six months of 2024, as compared to the same period of 2023, primarily due to a higher asset base.

•Deferral of regulatory assets increased $47 million in the first six months of 2024, as compared to the same period of 2023, primarily due to $89 million increase from higher net generation and transmission related deferrals, partially offset by $15 million decrease of certain Tax Act savings deferrals to FE PA customers, $3 million decrease in lower storm-related expense deferrals and $24 million net decrease in other deferrals.

•General taxes increased $11 million in the first six months of 2024, as compared to the same period of 2023, primarily due to higher gross receipts taxes.

Other Expense —

Other expense increased $44 million in the first six months of 2024, as compared to the same period of 2023, primarily due to the absence of the pension mark-to-market adjustment and higher net interest expense associated with new long-term debt issuances.

Income Taxes —

Distribution segment’s effective tax rate was 21.0% and 18.7% for the six months ended June 30, 2024 and 2023, respectively. The increase in the effective tax rate was primarily due to the absence of certain state income tax benefits in 2023 as well as a reduction in the tax benefit from amortization of excess deferred income taxes.

Integrated Segment — First Six Months of 2024 Compared with First Six Months of 2023

Integrated segment’s earnings attributable to FE increased $45 million in the first six months of 2024, as compared to the same period of 2023, primarily from the implementation of base rate cases, higher customer usage and demand, higher revenues from regulated investment programs, partially offset by higher other operating expenses, including increases in the ARO liability, and a higher effective tax rate due to discrete tax charges discussed below.

Revenues —

Integrated segment’s total revenues increased $289 million as a result of the following sources:

	For the Six Months Ended June 30,
Revenues by Type of Service	2024		2023		Increase (Decrease)
	(In millions)
Distribution services	720		644		$	76
Generation sales:
Retail	1,259		1,063		196
Wholesale	68		95		(27)
Total generation sales	1,327		1,158		169
Transmission revenues:
JCP&L	118		100		18
MP & PE	79		50		29
Total transmission revenues	197		150		47
Other	29		32		(3)
Total Revenues	$	2,273	$	1,984	$	289

Distribution services revenues increased $76 million in the first six months of 2024, as compared to the same period of 2023, primarily resulting from higher customer usage as a result of the weather, higher weather-adjusted customer usage and demand, higher revenues from the implementation of base rate cases, and higher rider revenues associated with certain investment programs. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.

Generation sales revenues increased $169 million in the first six months of 2024, as compared to the same period of 2023. primarily due to higher retail revenues, partially offset by lower wholesale revenues.

•Retail generation sales increased $196 million in the first six months of 2024, as compared to the same period in 2023 primarily due to higher customer usage as a result of the weather and higher non-shopping generation auction rates. Retail generation sales, other than those in West Virginia, have no material impact to earnings.

•Wholesale generation revenues decreased $27 million in the first six months of 2024, as compared to the same period in 2023, primarily due to lower capacity revenues and lower market prices, partially offset by higher sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.

Transmission revenues increased $47 million in the first six months of 2024, as compared to the same period of 2023, primarily due to higher rate base from regulated investment programs.

Operating Expenses —

Total operating expenses increased $164 million, primarily due to:

•Fuel costs decreased $40 million during the first six months of 2024, as compared to the same period of 2023, primarily due to lower unit costs, partially offset by higher generation output. Due to the ENEC, fuel expense has no material impact to earnings.

•Purchased power costs, which have no material impact to earnings, increased $27 million during the first six months of 2024, as compared to the same period of 2023, primarily due to higher unit costs, partially offset by lower capacity expenses and volumes.

•Other operating expenses increased $154 million in the first six months of 2024, as compared to the same period of 2023, primarily due to:

•$53 million pre-tax charge at JCP&L in the first quarter 2024 associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the base rate case settlement agreement, to be disallowed from future recovery;

•Higher storm expenses of $55 million, of which $47 million was deferred for future recovery;

•Higher network transmission expenses of $20 million, which were deferred for future recovery, resulting in no material impact to earnings;

•$16 million charge related to changes in ARO liabilities associated with final CCR rules;

•Higher planned vegetation management costs of $7 million, which were deferred for future recovery, in no material impact to earnings;

•Higher uncollectible expenses of $5 million, which were deferred for future recovery, primarily due to a reduction to the allowance during the second quarter of 2023;

•Higher energy efficiency and other state mandated program costs of $4 million, which were deferred for future recovery, resulting in no material impact to earnings; and

•Higher regulated generation outage spend of $4 million.

This increase was partially offset by:

•Lower other operating and maintenance expenses of $10 million, primarily due lower employee benefits and labor expenses, including the absence of benefit costs associated with the PEER program and involuntary separations that occurred in the second quarter of 2023.

•Depreciation expense increased $27 million in the first six months of 2024, as compared to the same period of 2023, primarily due to a higher asset base.

•Deferral of regulatory assets increased $10 million in the first six months of 2024, as compared to the same period of 2023, primarily due to:

•$60 million increase due to the approval in the first quarter of 2024 to recover costs of certain retired generation stations by the WVPSC;

•$48 million increase due to higher deferral of storm related expenses;

•$28 million related to net increases in other deferrals; and

•$7 million increase due to higher energy efficiency related deferrals.

This increase was partially offset by:

•$127 million net decrease due to lower generation and transmission related deferrals; and

•$6 million decrease due to higher vegetation management program related amortizations.

•General taxes increased $6 million in the first six months of 2024, as compared to the same period of 2023, primarily due to higher gross receipts taxes.

Other Expense —

Other expense increased $40 million in the first six months of 2024, as compared to the same period of 2023, primarily due to the absence of the pension mark-to-market adjustment, higher net interest expense associated with new long-term issuances since the second quarter of 2023, higher short-term borrowings, and higher non-recoverable charges related to abandoned transmission projects.

Income Taxes —

Integrated segment’s effective tax rate was 27.2% and 17.6% for the six months ended June 30, 2024 and 2023, respectively. The increase was primarily due to the net increase in income tax expense related to the remeasurement of a valuation allowance for the expected utilization of certain state NOL carryforwards recognized in 2023.

Stand-Alone Transmission Segment — First Six Months of 2024 Compared with First Six Months of 2023

Stand-Alone Transmission Segment’s earnings attributable to FE decreased $36 million in the first six months of 2024, as compared to the same period of 2023, primarily due to the dilutive effect of the 30% additional minority equity interest sale in FET that closed in March 2024, a discrete tax charge associated with the FET Equity Interest Sale and higher short-term borrowings and interest rates, partially offset by increased earnings as a result of regulated capital investments that increased rate base.

Revenues —

Stand-Alone Transmission’s total revenues increased $70 million, primarily due to a higher rate base and recovery of higher transmission operating expenses.

The following table shows revenues by transmission asset owner:

	For the Six Months Ended June 30,
Revenues by Transmission Asset Owner	2024		2023		Increase (Decrease)
	(In millions)
ATSI	$	509	$	471	$	38
TrAIL	140		134		6
MAIT	216		189		27
KATCo	43		42		1
Other	(2)		—		(2)
Total Revenues	$	906	$	836	$	70

Operating Expenses —

Total operating expenses increased $29 million in the first six months of 2024, as compared to the same period of 2023, primarily due to higher depreciation and property tax expenses from a higher asset base. Nearly all operating expenses are recovered through formula rates, resulting in no material impact to earnings.

Other Expense —

Total other expense increased $15 million in the first six months of 2024, as compared to the same period of 2023, primarily due to higher short-term borrowings and net interest expense due to the new debt issuances and the absence of the pension mark-to-market adjustment, partially offset by higher capitalized financing costs.

Income Taxes —

Stand-Alone Transmission’s effective tax rate was 30.3% and 22.5% for the six months ended June 30, 2024 and 2023, respectively. The increase in the effective tax rate is primarily due to a discrete tax charge related to updates to deferred taxes on the sale of equity interest in FET in the first quarter of 2024.

52

Corporate / Other — First Six Months of 2024 Compared with First Six Months of 2023

Financial results at Corporate/Other resulted in a $140 million increase in losses attributable to FE in the first six months of 2024, as compared to the same period of 2023, primarily due to:

•$120 million in loss contingencies associated with the SEC and OOCIC investigations as further discussed below in “Outlook - Other Legal Proceedings”;

•$115 million (after-tax) charge related to changes in ARO liabilities associated with final CCR rules and McElroy’s Run;

•$37 million (after-tax) in lower investment earnings related to FEV’s equity method investment in Global Holding; and

•$27 million (after-tax) of higher debt redemption costs, higher net interest expense associated with the 2026 Convertible Notes issuance in May 2023, and higher revolver borrowings and interest rate, partially offset by higher interest income related to the FET Equity Interest Sale promissory notes and money pool investments; and

•Higher net discrete income tax charges of $25 million related to the PA Consolidation, partially offset by income tax benefits related to updates to deferred taxes on the sale of equity interest in FET in the first quarter of 2024 and the absence of a $9 million discrete income tax charge recognized in 2023 due to the remeasurement of a valuation allowance for the expected utilization of certain state NOL carryforwards.

These losses were partially offset by:

•$116 million (after-tax) of proceeds from the shareholder derivative lawsuit settlement as described below in “Outlook - Other Legal Proceedings”;

•$21 million (after-tax) of lower other operating expenses primarily related to the absence of expenses associated with the cancellation of a sponsorship agreement during the first quarter of 2023;

•$8 million (after-tax) related to lower pension and OPEB non-service costs; and

•$4 million (after-tax) from the absence of the pension mark-to-market adjustment.

REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Electric Companies and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.

Management assesses the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability relate to changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets and liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

The following table provides information about the composition of net regulatory assets and liabilities as of June 30, 2024, and December 31, 2023, and the changes during the six months ended June 30, 2024:

Net Regulatory Assets (Liabilities) by Source	June 30, 2024		December 31, 2023		Change
	(In millions)
Customer payables for future income taxes	$	(2,325)	$	(2,382)	$	57
Spent nuclear fuel disposal costs	(74)		(83)		9
Asset removal costs	(680)		(652)		(28)
Deferred transmission costs	309		286		23
Deferred generation costs	555		572		(17)
Deferred distribution costs	260		247		13
Storm-related costs	901		799		102
Energy efficiency program costs	254		198		56
New Jersey societal benefit costs	84		79		5
Vegetation management costs	98		102		(4)
Other	67		(11)		78
Net Regulatory Liabilities included on the Consolidated Balance Sheets	$	(551)	$	(845)	$	294

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The following is a description of the regulatory assets and liabilities described above:

Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to federal and state tax rate changes such as the Tax Act and Pennsylvania House Bill 1342. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset.

Spent nuclear fuel disposal costs - Reflects amounts collected from customers, and the investment income, losses and changes in fair value of the trusts for spent nuclear fuel disposal costs related to former nuclear generating facilities, Oyster Creek and Three Mile Island Unit 1.

Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement.

Deferred transmission costs - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed, including amounts expected to be refunded to, or recoverable from, wholesale transmission customers resulting from the FERC Audit, as further described below, which amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods. Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.

Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. Generally, the ENEC rate is updated annually. Also included is a regulatory asset related to approval by the WVPSC in March 2024 to recover costs associated with certain retired generation plants in West Virginia (amortized through 2029).

Deferred distribution costs - Relates to the Ohio Companies' deferral of certain distribution-related expenses, including interest (amortized through 2034), AMI costs in New Jersey, and other distribution-related costs being recovered in West Virginia.

Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $326 million and $254 million are currently being recovered through rates as of June 30, 2024 and December 31, 2023, respectively.

Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including, New Jersey energy efficiency and renewable energy programs, FE PA’s Energy Efficiency and Conservation programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland surcharge. Investments in certain of these energy efficiency programs earn a long-term return.

New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and the New Jersey Clean Energy Program.

Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey and West Virginia as well as certain transmission vegetation management costs at MAIT, ATSI, KATCo and PE (amortized through 2024, 2030 and 2036, respectively).

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The following table provides information about the composition of net regulatory assets that do not earn a current return as of June 30, 2024 and December 31, 2023, of which approximately $688 million and $371 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:

Regulatory Assets by Source Not Earning a Current Return	June 30, 2024		December 31, 2023		Change
	(In millions)
Deferred transmission costs	$	4	$	6	$	(2)
Deferred generation costs	321		432		(111)
Deferred distribution costs	137		68		69
Storm-related costs	659		602		57
Vegetation management costs	17		21		(4)
Other	81		68		13
Regulatory Assets Not Earning a Current Return	$	1,219	$	1,197	$	22

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction and other investment expenditures, scheduled debt maturities and interest payments, dividend payments and potential contributions to its pension plan.

FE and its subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2024 and beyond, FE and its subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its subsidiaries to, among other things, fund capital expenditures and other capital-like investments, and refinance short-term and maturing long-term debt, subject to market conditions and other factors. FE may utilize instruments other than senior notes to fund its liquidity and capital requirements, including hybrid securities.

In alignment with FirstEnergy’s strategy to invest in its segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated subsidiaries to issue and/or refinance debt.

Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.

On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes. Interest income associated with the promissory notes was $20 million and $21 million for the three and six months ended June 30, 2024, respectively, and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. FE PA serves an area with a population of approximately 4.5 million and operates under the rate districts of the former Pennsylvania Companies. FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.

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Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.

Post-pandemic economic conditions have stabilized across numerous material categories, but lead times have not returned to pre-pandemic levels. Several key suppliers have seen improvements with labor shortages and raw material availability and FirstEnergy continues to monitor the situation as capacity can be constrained with increased demand. Inflationary pressures have moderated, which has positively impacted the cost of materials, but certain categories have remained elevated. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect service disruptions or any material impact on its capital investment plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.

In December 2023, FirstEnergy, executed a lift-out transaction with Banner Life Insurance Company and Reinsurance Group of America that transferred approximately $683 million of plan assets and $719 million of plan obligations, associated with approximately 1,900 former competitive generation employees, who will assume future and full responsibility to fund and administer their benefit payments. There was no change to the pension benefits for any participants as a result of the transfer. The transaction was funded by pension plan assets and resulted in a pre-tax gain of approximately $36 million, which was included in the fourth quarter 2023 pension mark-to-market charge. FirstEnergy expects that the transaction further de-risked potential volatility with the pension plan assets and liabilities, and FirstEnergy is currently evaluating another lift-out in 2024 of approximately $700 million in pension assets and plan obligations associated with former competitive generation employees based on market and other conditions.

As of June 30, 2024, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to current portion of long-term debt, accounts payable, short-term borrowings and accrued interest, taxes, and compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below.

Short-Term Borrowings / Revolving Credit Facilities

On October 18, 2021, FE, FET, the Electric Companies, ATSI, MAIT and TrAIL entered into the 2021 Credit Facilities, which were six separate senior unsecured five-year syndicated revolving credit facilities with JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd. and PNC Bank, National Association that replaced the FE Revolving Facility and the FET Revolving Facility, and provide for aggregate commitments of $4.5 billion. Under the 2021 Credit Facilities, an aggregate amount of $4.5 billion is available to be borrowed, repaid and reborrowed, subject to each borrower’s respective sublimit under the respective facilities. These credit facilities provide substantial liquidity to support the Regulated businesses, and each of the operating companies within the businesses.

On October 20, 2023, FE and certain of its subsidiaries entered into the amendments to each of the 2021 Credit Facilities to, among other things; (i) amend the FE Revolving Facility to release FET as a borrower and (ii) extend the maturity date of the 2021 Credit Facilities for an additional one-year period, from October 18, 2026 to October 18, 2027. Also, on October 20, 2023, each of FET and KATCo entered into the 2023 Credit Facilities. In connection with PA Consolidation, the Pennsylvania Companies' rights and obligations under their revolving credit facility were assumed by FE PA on January 1, 2024.

Under the FET Revolving Facility, $1.0 billion is available to be borrowed, repaid and reborrowed until October 20, 2028. Under the KATCo Revolving Facility, (i) $150 million is available to be borrowed, repaid and reborrowed until October 20, 2027, (ii) borrowings will mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended; upon KATCo demonstrating to the administrative agent authorization to borrow amounts maturing more than 364 days from the date of borrowing, its borrowings will mature on the latest commitment termination date.

The 2021 Credit Facilities and 2023 Credit Facilities are as follows:

•FE, $1.0 billion revolving credit facility;

•FET, $1.0 billion revolving credit facility;

•Ohio Companies, $800 million revolving credit facility;

•FE PA, $950 million revolving credit facility;

•JCP&L, $500 million revolving credit facility;

•MP and PE, $400 million revolving credit facility;

•ATSI, MAIT and TrAIL, $850 million revolving credit facility; and

•KATCo, $150 million revolving credit facility.

Borrowings under the 2021 Credit Facilities and 2023 Credit Facilities may be used for working capital and other general corporate purposes. Generally, borrowings under each of the credit facilities are available to each borrower separately and

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mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 2021 Credit Facilities and 2023 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities and 2023 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 2021 Credit Facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021.

FirstEnergy’s 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on FirstEnergy’s results of operations, cash flows, financial condition and liquidity.

FirstEnergy had $795 million and $775 million of outstanding short-term borrowings as of June 30, 2024 and December 31, 2023, respectively. FirstEnergy’s available liquidity from external sources as of July 29, 2024, was as follows:

Revolving Credit Facility	Maturity	Commitment		Available Liquidity
		(In millions)
FE	October 2027	$	1,000	$	997
FET	October 2028	1,000		785
Ohio Companies	October 2027	800		769
FE PA	October 2027	950		932
JCP&L	October 2027	500		470
MP and PE	October 2027	400		348
ATSI, MAIT and TrAIL	October 2027	850		850
KATCo	October 2027	150		150
	Subtotal	$	5,650	$	5,301
Cash and cash equivalents		—		508
	Total	$	5,650	$	5,809

The following table summarizes the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of June 30, 2024:

Individual Borrower	Regulatory Debt Limitations			Credit Facility Limitations			Debt-to-Total-Capitalization Ratio
	(In millions)
FE		N/A			$	1,000		N/A(2)
ATSI(1)		$	500		350			40.4	%
CEI(1)		500			300			48.2	%
FET		N/A			1,000			64.0	%
FE PA(1)		1,250			950			51.3	%
JCP&L(1)		1,000			500			30.5	%
KATCo		200			150			N/A(3)
MAIT(1)		400			350			40.7	%
MP(1)		500			250			52.3	%
OE(1)		500			300			55.9	%
PE(1)		150			150			50.8	%
TE(1)		300			200			48.4	%
TrAIL(1)		400			150			38.5	%

(1) Includes amounts which may be borrowed under the regulated companies’ money pool.

(2) FE is not required to maintain a debt-to-total-capitalization ratio under the 2021 Credit Facilities and 2023 Credit Facilities. However, FE is required to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021. FE's interest coverage ratio as of June 30, 2024 was 4.21.

(3) KATCo does not have any outstanding debt as of June 30, 2024.

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Subject to each borrower’s sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the 2021 Credit Facilities and 2023 Credit Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the 2021 Credit Facilities and 2023 Credit Facilities and against the applicable borrower’s borrowing sublimit. As of June 30, 2024, FirstEnergy had $135 million in outstanding LOCs.

Revolving Credit Facility	LOC Availability as of June 30, 2024		LOC Utilized as of June 30, 2024
	(In millions)
FE	$	100	$	3
FET	100		—
Ohio Companies	150		31
FE PA	200		19
JCP&L	100		30
MP and PE	100		52
ATSI, MAIT and Trail	200		—
KATCo	35		—

The 2021 Credit Facilities and 2023 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the 2021 Credit Facilities and the 2023 Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 2021 Credit Facilities and 2023 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.

As of June 30, 2024, the borrowers were in compliance with the applicable interest coverage and debt-to-total-capitalization ratio covenants in each case as defined under the 2021 Credit Facilities and 2023 Credit Facilities.

FirstEnergy Money Pools

FirstEnergy’s regulated operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. As of June 1, 2024, FET is no longer participating in the unregulated money pool. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher.

Average Interest Rates	Regulated Companies’ Money Pool				Unregulated Companies’ Money Pool
	2024		2023		2024		2023
For the Three Months Ended June 30,	6.21	%	6.15	%	6.69	%	6.08	%
For the Six Months Ended June 30,	6.26	%	6.00	%	6.89	%	5.64	%

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Long-Term Debt Capacity

FE’s and its subsidiaries’ access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of July 29, 2024:

Corporate Credit Rating

Senior Secured

Senior Unsecured

Outlook/Credit/Watch(1)

Issuer

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

FE

BBB

Baa3

BBB-

—

—

—

BBB-

Baa3

BBB-

P

S

P

Distribution:

CEI

BBB

Baa3

BBB+

A-

Baa1

A

BBB

Baa3

A-

P

S

S

OE

BBB+

A3

BBB+

A

A1

A

BBB+

A3

A-

P

S

S

TE

BBB+

Baa2

BBB+

A

A3

A

—

—

—

P

S

S

FE PA

BBB+

A3

BBB+

A

A1

—

BBB+

A3

A-

P

S

P

Integrated:

JCP&L

BBB

A3

BBB+

—

—

—

BBB

A3

A-

P

S

P

MP

BBB

Baa2

BBB+

A-

A3

A

BBB

Baa2

—

S

S

P

AGC

BBB-

Baa2

BBB+

—

—

—

—

—

—

S

S

P

PE

BBB

Baa2

BBB+

A-

A3

A

—

—

—

S

S

S

Transmission:

FET

A-

Baa2

BBB

—

—

—

BBB+

Baa2

BBB

P

S

P

ATSI

A-

A3

A-

—

—

—

A-

A3

A

P

S

P

MAIT

A-

A3

A-

—

—

—

A-

A3

A

P

S

P

TrAIL

A-

A3

A-

—

—

—

A-

A3

A

P

S

P

KATCo

—

A3

BBB+

—

—

—

—

—

—

—

S

P

(1) S = Stable, P = Positive

On May 6, 2024, Fitch upgraded all subsidiaries and put FE and several subsidiaries on positive outlook.

On July 22, 2024, S&P upgraded FET two notches and ATSI, MAIT and TrAIL one notch while maintaining positive outlooks.

The applicable undrawn and drawn margin on the 2021 Credit Facilities and 2023 Credit Facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments under the 2021 Credit Facilities and 2023 Credit Facilities are based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s. The fees paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.

The interest rates payable on approximately $2.1 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable governing documents. Generally, a one-notch downgrade by the applicable rating agency may result in a 25 basis point coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.

Debt capacity is subject to the consolidated interest coverage ratio in the 2021 Credit Facilities. As of June 30, 2024, FirstEnergy could incur approximately $800 million of incremental interest expense or incur a $2.0 billion reduction to the consolidated interest coverage earnings numerator, as defined under the covenant, and FE would remain within the limitations of the financial covenant requirements of the 2021 Credit Facilities.

Cash Requirements and Commitments

FirstEnergy has certain obligations and commitments to make future payments under contracts. For an in-depth discussion of FirstEnergy’s cash requirements and commitments, see “Capital Resources and Liquidity - Cash Requirements and Commitments" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" within FirstEnergy’s Form 10-K for the year ended December 31, 2023 (filed on February 13, 2024).

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Changes in Cash Position

As of June 30, 2024, FirstEnergy had $60 million of cash and cash equivalents and $43 million of restricted cash as compared to $137 million of cash and cash equivalents and $42 million of restricted cash as of December 31, 2023, on the Consolidated Balance Sheets.

The following table summarizes the major classes of cash flow items:

	For the Six Months Ended June 30,
(In millions)	2024		2023
Net cash provided from (used for) operating activities	$	1,072	$	(213)
Net cash used for investing activities	(1,876)		(1,547)
Net cash provided from financing activities	728		1,768
Net change in cash, cash equivalents, and restricted cash	(76)		8
Cash, cash equivalents, and restricted cash at beginning of period	179		206
Cash, cash equivalents, and restricted cash at end of period	$	103	$	214

Cash Flows From Operating Activities

FirstEnergy’s most significant sources of cash are derived from electric service provided by its operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve shopping customers, pension contributions and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.

Cash provided from (used for) operating activities was $1.1 billion and $(213) million in the first six months of 2024 and 2023, respectively. Compared to the same period of 2023, the increase in cash provided from (used for) operating activities is primarily due to:

•Lower payments, primarily on generation energy purchases for certain customers, net of related customer receivable receipts;

•The decrease in return of cash collateral to certain generation suppliers that serve shopping customers that was previously received as a result of changes in power prices;

•$750 million cash contribution to qualified pension plan in the second quarter of 2023;

•Settlement of the derivative lawsuits in the second quarter of 2024;

•Higher net transmission revenue collection based on the timing of formula rate collections; and

•Higher returns from distribution, integrated, and transmission capital investments.

The increase in cash provided from (used for) operating activities was partially offset by:

•Lower dividend distribution received by FEV from its equity investments in Global Holding; and

•Higher payments associated with Pennsylvania gross receipts taxes.

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Cash Flows From Investing Activities

Cash used for investing activities in the first six months of 2024 principally represented cash used for capital investments. The following table summarizes investing activities for the first six months of 2024 and 2023:

	For the Six Months Ended June 30,
Cash Used for Investing Activities	2024		2023		Increase (Decrease)
	(In millions)
Capital investments:
Distribution Segment	$	469	$	429	$	40
Integrated Segment	663		512		151
Stand-Alone Transmission Segment	576		458		118
Corporate / Other Segment	24		19		5
Asset removal costs	135		117		18
Other	9		12		(3)
	$	1,876	$	1,547	$	329

Cash used for investing activities for the first six months of 2024 increased $329 million, compared to the same period of 2023, primarily due to capital investments.

Cash Flows From Financing Activities

In the first six months of 2024 and 2023, cash provided from financing activities was $728 million and $1.8 billion, respectively. The following table summarizes financing activities for the first six months of 2024 and 2023:

	For the Six Months Ended June 30,
Financing Activities	2024		2023
	(In millions)
New Issues:
Unsecured notes	$	400	$	1,050
Unsecured convertible notes	—		1,500
FMBs	—		50
	$	400	$	2,600
Redemptions / Repayments:
Unsecured notes	$	(963)	$	(494)
FMBs	(400)		—
Senior secured notes	(23)		(21)
	$	(1,386)	$	(515)
Noncontrolling interest cash distributions	$	(15)	$	(53)
Short-term borrowings, net	20		250
Proceeds from FET Equity Interest Sale	2,300		—
Common stock dividend payments	(480)		(447)
Other	(111)		(67)
	$	728	$	1,768

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FirstEnergy had the following issuances and redemptions during the six months ended June 30, 2024:

Company	Type	Redemption / Issuance Date	Interest Rate	Maturity	Amount (In millions)	Description
Redemptions
FE	Unsecured Notes	April, 2024	7.375%	2031	$463	FE redeemed all of its remaining $463 million of 2031 Notes including a premium of approximately $80 million ($63 million after-tax). In addition, FE recognized approximately $4 million ($3 million after-tax) of deferred cash flow hedge losses and $1 million in other unamortized debt costs and fees associated with the FE debt redemptions.
JCP&L	Unsecured Notes	April, 2024	4.70%	2024	$500	JCP&L redeemed unsecured notes that became due.
MP	FMBs	April, 2024	4.10%	2024	$400	MP redeemed FMBs that became due.
Issuances
ATSI	Unsecured Notes	March, 2024	5.63%	2034	$150	Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MAIT	Unsecured Notes	May, 2024	5.94%	2034	$250	Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.

FE or its affiliates may, from time to time, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as FE or its affiliates may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors.

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications, which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FE and its subsidiaries could be required to make under these guarantees as of June 30, 2024, was $955 million, as summarized below:

Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FE’s Guarantees on Behalf of its Consolidated Subsidiaries(1)
Deferred compensation arrangements	$	426
Vehicle leases	75
Other	15
	516
FE’s Guarantees on Other Assurances
Surety Bonds(2)	191
Deferred compensation arrangements	113
LOCs	135
	439
Total Guarantees and Other Assurances	$	955

(1) During the third quarter of 2023, FE was required by PJM to issue a guarantee to cover non-performance until FE PA is able to provide audited financial statements to PJM, which is expected to occur in early 2025. The guarantee is expected to be immaterial to FE.

(2) During the second quarter of 2023, FE was released from its $169 million surety bond to the Pennsylvania Department of Environmental Protection related to the Little Blue Run Disposal Impoundment.

Collateral and Contingent-Related Features

In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

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As of June 30, 2024, $135 million of collateral has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $34 million of net cash collateral as of June 30, 2024, from certain generation suppliers, and such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.

These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2024:

Potential Collateral Obligations		Electric Companies and Transmission Companies		FE		Total
	(In millions)
Contractual obligations for additional collateral
Upon further downgrade		$	82	$	1	$	83
Surety bonds (collateralized amount)(1)		97		79		176
Total Exposure from Contractual Obligations		$	179	$	80	$	259

(1) Surety bonds are not tied to a credit rating. Surety bonds’ impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.

MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Enterprise Risk Management Committee, comprised of members of senior management, provides general oversight for risk management activities throughout FirstEnergy.

Commodity Price Risk

FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, such as prices for electricity, coal and energy transmission. FirstEnergy’s Risk Management Department and Enterprise Risk Management Committee are responsible for promoting the effective design and implementation of sound risk management programs and overseeing compliance with corporate risk management policies and established risk management practice.

The valuation of derivative contracts is based on observable market information. As of June 30, 2024, FirstEnergy has a net asset of $8 million in non-hedge derivative contracts that are related to FTRs at certain of the Electric Companies. FTRs are subject to regulatory accounting and do not impact earnings. See Note 6, “Fair Value Measurements,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s FTRs.

Equity Price Risk

As of June 30, 2024, the FirstEnergy pension plan assets were allocated approximately as follows: 24% in equity securities, 23% in fixed income securities, 7% in alternatives, 11% in real estate, 19% in private debt/equity, 6% in derivatives and 10% in cash and short-term securities. As discussed above, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan on May 12, 2023. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2028, which based on various assumptions, including an expected rate of return on assets of 8.0%, is expected to be approximately $260 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily.

As of June 30, 2024, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 51% in equity securities, 43% in fixed income securities and 6% in cash and short-term securities. See Note 4, “Pension and Other Post-Employment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans.

In the six months ended June 30, 2024, FirstEnergy’s OPEB plan assets have gained approximately 7.1% as compared to an annualized expected return on plan assets of 7.0%. In the six months ended June 30, 2024, FirstEnergy’s pension plan assets have lost approximately 0.4% as compared to an annualized expected return on plan assets of 8.0%.

Interest Rate Risk

FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.

The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is

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triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs for 2024, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market.

FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of June 30, 2024, the spot rate was 5.48% and 5.41% for pension and OPEB obligations, respectively, as compared to 5.05% and 4.97% as of December 31, 2023, respectively.

The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2024.

FirstEnergy’s 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher.

Economic Conditions

Post-pandemic economic conditions have stabilized across numerous material categories, but lead times have not returned to pre-pandemic levels. Several key suppliers have seen improvements with labor shortages and raw material availability and FirstEnergy continues to monitor the situation as capacity can be constrained with increased demand. Inflationary pressures have moderated, which has positively impacted the cost of materials, but certain categories have remained elevated. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect service disruptions or any material impact on its capital investment plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.

CREDIT RISK

Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains risk policies and procedures with respect to counterparty credit (including a requirement that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. FirstEnergy has concentrations of suppliers and customers among electric companies, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy’s overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy’s credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties’ credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

OUTLOOK

    INCOME TAXES

The IRA of 2022, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement NOLs can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury during 2022 and 2023, FirstEnergy continues to believe that it is more likely than not that AMT will be applicable beginning with 2023. The future issuance of U.S. Treasury regulations could significantly change FirstEnergy’s AMT estimates or its conclusion as to whether it is an AMT payer at all. Additionally, the regulatory treatment of the impacts of this legislation may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in this legislation, including guidance from the U.S. Treasury and/or the IRS or unfavorable regulatory treatment, could negatively impact FirstEnergy’s cash flows, results of operations, and financial condition. As further discussed below, FirstEnergy expects to pay regular federal corporate income tax in 2024, due in large part to the gain realized from closing the FET Equity Interest Sale.

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As discussed above, on March 25, 2024, FirstEnergy closed on the FET Equity Interest Sale, realizing an approximate $7.3 billion tax gain from the combined sale of 49.9% of the membership interests in FET for the consideration received and recapture of negative tax basis in FET. In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% sale of FET in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA Consolidation. During the first quarter of 2024, FirstEnergy also recognized a reduction to OPIC of approximately $797 million for federal and state income tax associated with the tax gain from closing on the FET Equity Interest Sale. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards that will be used to offset a majority of the tax gain from the FET Equity Interest Sale and expected taxable income in 2024, however, due to certain limitations on NOL utilization enacted in the Tax Act, FirstEnergy expects that a portion of the NOL will carry into 2025 and possibly beyond. As a result of the FET Equity Interest Sale, FET and its subsidiaries deconsolidated from FirstEnergy’s consolidated federal income tax group and now constitute their own consolidated federal income tax group subject to their own income tax allocation agreement.

Due to a private letter ruling recently issued by the IRS to an unaffiliated utility company, FirstEnergy is evaluating the potential requirement to transition certain of its Electric Companies and Transmission Companies to stand-alone treatment of NOL carryforwards for ratemaking purposes. Currently, none of FirstEnergy’s Electric Companies or Transmission Companies have transitioned to stand-alone treatment. FirstEnergy expects that if and where transitioning is required, those impacted Electric Companies and Transmission Companies will make the appropriate regulatory filing(s) in their applicable jurisdiction to include the NOL carryforward deferred tax asset in rate base and revenue requirement, which could have a material, favorable impact on future net income.

STATE REGULATION

Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.

The EmPOWER Maryland program previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. PE recovers EmPOWER program costs with a return on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding. Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025, and 100% in 2026 and beyond. Notwithstanding the order to phase out the unamortized balances of EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and was to be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the unamortized balances was extended through the end of 2030. On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years. New legislation signed into law on May 9, 2024, and effective July 1, 2024, is expected to reduce the pre-tax return on the EmPOWER Maryland programs for PE by a total of $25 to $30 million over the period of 2024-2030.

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NEW JERSEY

JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third- party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

The base rate increase approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and became effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L was amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.

JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On May 22, 2024, the NJBPU approved JCP&L’s request for a six-month extension of the EE&C Plan I, to December 31, 2024. The budget for the extension period adds approximately $69 million to the original program cost and JCP&L will recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and has a proposed budget of approximately $964 million. EE&C Plan II consists of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. Public hearings were held on June 11, 2024, and the parties are currently engaged in settlement discussions. On July 1, 2024, the NJBPU suspended the procedural schedule. A final NJBPU decision and order is required no later than October 15, 2024.

The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L and one other party filed comments on July 31, 2023.

On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. At this time, Orsted’s announcement does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.

Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the United States Department of Energy to finance a portion of the project using low-interest rate loans available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024, which was approved on May 17, 2024.

On April 3, 2024, Mid-Atlantic Offshore Development, LLC submitted a bid application for the NJBPU Prebuild Infrastructure Solicitation to the NJBPU which outlines its proposal to construct infrastructure connecting the identified landing point for offshore wind generation off the coast of New Jersey with the high-voltage electric grid at Larrabee Collector Station. JCP&L was described in the application as a joint developer with Mid-Atlantic Offshore Development, LLC, subject to the execution of a joint development agreement by the parties. Mid-Atlantic Offshore Development, LLC would have been the party responsible for the

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project. Mid-Atlantic Offshore Development, LLC, is no longer advancing its application to the NJBPU for the Prebuild Infrastructure Solicitation.

On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, as amended, if approved will result in the investment of approximately $930.5 million of total estimated costs over five years.

OHIO

The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continued the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with revenue cap increases of $15 million per year through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.

On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies request a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, and reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony and expect by month-end to file an update with an adjusted net increase of base distribution revenues and incorporating matters in the rate case as directed by the PUCO’s ESP V Order.

On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications. ESP V, as modified by the PUCO, became effective June 1, 2024 and continues through May 31, 2029, and provides for, among other things, the continuation of existing riders related to purchased power, transmission and uncollectibles, the continuation of the DCR rider with proposed annual revenue cap increases until new base rates are established, the continuation of the AMI rider, and the addition of new riders for storm recovery and vegetation management, with terms and conditions to be established in the base rate case. The ESP V order additionally directed the Ohio Companies to file another base distribution rate case not later than May 31, 2028, develop an electric vehicle education program to assist customers in transitioning to electric vehicles and contribute $32.5 million during the term of ESP V to fund low-income customer bill assistance programs and bill assistance for income-eligible senior citizens, which was recognized in the second quarter of 2024 within “Other operating expenses” at the Regulated Distribution segment and on FirstEnergy’s Consolidated Statements of Income. On June 14, 2024, the Ohio Companies filed an Application for Rehearing seeking greater certainty regarding the key terms of ESP V over the approved term and proposed modifications to the May 15, 2024 order. The Ohio Companies also proposed modifications to ESP V to resolve their Application for Rehearing including, among other things, a reduced three-year ESP V term, approval of certain riders over the full three-year proposed ESP V term, full recovery of investments in the DCR and proposed modifications to preserve the economic value of the Order for customers, including a commitment to forego pursuit of the Ohio Companies' request for an enhanced vegetation management program in the 2024 base distribution rate case. Other parties also filed applications for rehearing. All applications for rehearing remain pending before the PUCO.

On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2023, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2024, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV

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for calendar year 2023, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. These matters remain pending before the PUCO.

On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 15, 2024, the Ohio Companies filed a motion to consolidate their phase two distribution grid modernization plan proceeding with three audit proceedings pending before the PUCO, which was granted on May 23, 2024. Evidentiary hearings began on June 5, 2024 and concluded on July 2, 2024.

On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below and set a procedural schedule, which was vacated on March 15, 2024. On June 21, 2024, the Attorney Examiners issued an entry setting a procedural schedule, which was modified on July 16, 2024. Evidentiary hearings are scheduled to begin February 3, 2025.

On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the DCR rider audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner directed the third-party auditor to file its report by August 28, 2024.

In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements.

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Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiners set a procedural schedule, which was vacated on March 15, 2024. On June 21, 2024, the Attorney Examiners issued an entry setting a procedural schedule and scheduling evidentiary hearings to begin October 9, 2024.

In connection with an ongoing annual audit of the Ohio Companies’ DCR rider for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through the DCR rider or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement, and set a procedural schedule, which was vacated on March 15, 2024. On June 21, 2024, the Attorney Examiners issued an order setting a procedural schedule, which was modified on July 16, 2024. Evidentiary hearings are scheduled to begin February 3, 2025.

On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or the, now-deceased, former chairman of the PUCO through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered.

On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing.

In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.

See below for additional details on the government investigations and ongoing litigation surrounding the investigation of HB 6.

PENNSYLVANIA

The Pennsylvania Companies operated under rates approved by the PPUC, effective as of January 27, 2017. On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.

Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31,

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2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the next phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period beginning January 1, 2025 and ending December 31, 2029.

On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.

On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requests a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing include a proposal to change pension recovery from average cash contributions to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requests an enhanced ten year vegetation management program and recovery of certain incurred costs, including major storms, COVID-19, a program to convert streetlights to LEDs, and others. The PPUC issued an order on April 25, 2024, deferring, by operation of law, the June 1, 2024 statutory effective date to January 1, 2025. A pre-hearing conference was held on May 2, 2024, at which time the procedural litigation schedule was set. Hearings are scheduled to begin August 15, 2024. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually.

On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, includes the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 will be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.

On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. The first solar generation site went into service in January 2024 and construction of the remaining four sites are expected to be completed no later than the end of 2025 at a total investment cost of approximately $110 million. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024.

On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE were seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and new depreciation rates became effective on March 27, 2024.

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On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlement with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.

FERC REGULATORY MATTERS

Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions.

Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.

FERC Audit

FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy

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recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $64 million of costs have been recovered as of June 30, 2024. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Electric Companies are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. If FirstEnergy is unable to recover these transmission or distribution costs, it could result in future charges and/or adjustments and have an adverse impact on FirstEnergy’s financial condition.

ATSI ROE – Ohio Consumers Counsel v. ATSI, et al.

On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.

Transmission ROE Methodology

A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis.

Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.

On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.

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CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.

Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the U.S. Supreme Court. Oral argument was heard on February 21, 2024. On June 27, 2024, the U.S. Supreme Court granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit.

Climate Change

In March 2024, the SEC issued final rules to require public companies to disclose certain climate-related information in registration statements and annual reports filed with the SEC. As adopted, the final climate disclosure rules mandate the disclosure of climate-related risks and the material impacts that severe weather events and other natural conditions have had, or are reasonably likely to have, on FirstEnergy, as well as disclosures related to management and FE Board oversight of such risks. In April 2024, the SEC voluntarily stayed the final climate disclosure rules pending resolution of legal challenges. FirstEnergy currently is assessing the impact of the final climate disclosure rules on its business. There are several initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

As part of its climate strategy, FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). With respect to our coal-fired plants in West Virginia, which serve as the primary source of our Scope 1 emissions, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. FirstEnergy cannot currently estimate the financial impact of climate change policies, including the final SEC rules, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-

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fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule. Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft. Martin and Harrison power stations.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the 5th and 8th Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the Rule pending disposition on the merits. Depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of June 30, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. AE Supply continues to evaluate closure options for McElroy’s Run, including the potential transfer of the site and remediation obligations to

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a third-party, as well as other interpretation changes to its closure plans. As a result, during the second quarter of 2024, AE Supply reviewed its ARO and future expected costs to remediate McElroy’s Run and the adjacent dry landfill, resulting in an increase to the ARO liability and corresponding increase to Other Operating expense of $87 million, which is further described above in Note 8, “Asset Retirement Obligations.” AE Supply continues to evaluate closure options for McElroy’s Run.

On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. Depending on the outcome of appeals and the ultimate implementation of the final rule, compliance with these standards could require remedial actions, including removal of coal ash. See Note 8, “Asset Retirement Obligations,” above for a description of the $125 million increase to its ARO FirstEnergy recorded during the second quarter of 2024 as a result of its analysis.

FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of June 30, 2024 based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $96 million have been accrued through June 30, 2024, of which approximately $69 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

United States v. Larry Householder, et al.

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the U.S Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.

On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 21, 2024, FirstEnergy has successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S Attorney’s Office. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information.

Legal Proceedings Relating to United States v. Larry Householder, et al.

On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers relating to the

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conduct described in the DPA. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. FirstEnergy has cooperated fully with the SEC investigation. FE is working to finalize an agreement-in-principle with the staff of the SEC based upon facts set forth in the DPA that would fully resolve the investigation, which proposed settlement remains subject to approval of the SEC. FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation, and in the second quarter of 2024, a loss contingency of $100 million was recorded and included in “Other Operating expenses” on the Consolidated Statements of Income at Corporate/Other for segment reporting.

On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the, now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and finalize an appropriate resolution of the investigation with respect to FE, which is expected to include a non-prosecution agreement. FE believes that it is probable that it will incur a loss in connection with the resolution of this matter and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp., noted below and, in the second quarter of 2024, a loss contingency of $19.5 million was recorded and included in “Other Operating expenses” on the Consolidated Statements of Income at Corporate/Other for segment reporting.

In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order; the Sixth Circuit granted FE’s petition on November 16, 2023, and conducted oral argument on July 17, 2024. On November 30, 2023, FE filed a motion with the S.D. Ohio to stay all proceedings pending the circuit court appeal. All discovery is stayed during the pendency of the district court motion. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

•MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio); on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. All discovery is stayed during the pendency of the district court motion in In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In

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connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills will include new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the case in light of the February 9, 2024, indictments against defendants in this action, which the court granted on March 14, 2024. In connection with the ongoing OOCIC resolution discussions, FE is also discussing an appropriate settlement of this civil action with the OAG. FE believes that it is probable that it will incur a loss in connection with the resolution of this matter and the ongoing OOCIC investigation and, as noted above, in the second quarter of 2024, a loss contingency of $19.5 million was recorded.

On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:

•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.

•Miller v. Anderson, et al. (N.D. Ohio); on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon the approval of the settlement by the S.D. Ohio, which was granted on May 17, 2024.

•Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); on September 1, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022, which was appealed by a purported FE stockholder on June 15, 2023. The U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. All appeal options were exhausted on May 16, 2024.

The above settlement included a series of corporate governance enhancements and a payment to FE of $180 million, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs, and a $7 million net return on deposited funds, which was received in the second quarter of 2024. The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.

The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 9, “Regulatory Matters.”

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations, and cash flows.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 1, "Organization and Basis of Presentation," for a discussion of new accounting pronouncements.

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ITEM 3.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “FirstEnergy Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.

ITEM 4.     CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The management of FirstEnergy, with the participation of the Chief Executive Officer and Chief Financial Officer, have reviewed and evaluated the effectiveness of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of FirstEnergy have concluded that its disclosure controls and procedures were effective as of the end of the period covered by this report.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2024, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.        LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Note 9, “Regulatory Matters,” and Note 10, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A.    RISK FACTORS

You should carefully consider the risk factors discussed in "Item 1A. Risk Factors" in FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2023, and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, which could materially affect FirstEnergy’s business, financial condition or future results. The information set forth in this report, including without limitation, the risk factor(s) presented below, updates and should be read in conjunction with, the risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2023, and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2024.

The Physical Risks Associated with Climate Change May Have an Adverse Impact on Our Business Operations, Financial Condition and Cash Flows.

Physical risks of climate change such as flooding, wildfires, rising sea levels, and other related phenomena, resulting from more frequent or more extreme weather events and changes in temperature and precipitation patterns associated with climate change, could affect some, or all, of our operations. Frequent or extreme weather events could disrupt our operations and/or be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Electric Companies’ and Transmission Companies’ service areas could also directly affect their capital assets, such as downed wires, poles, or damage to other operating equipment, resulting in service disruptions to customers and possibly creating hazardous conditions. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions, and in some instances, we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our business operations, financial condition and cash flows.

Climate change poses other financial risks as well. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased revenues, margins or earnings.

ITEM 2.        UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.        DEFAULTS UPON SENIOR SECURITIES

None.

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ITEM 4.        MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.        OTHER INFORMATION

Trading Arrangements

During the quarter ended June 30, 2024, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of FE adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408 of Regulation S-K).

ITEM 6.        EXHIBITS

Exhibit Number		Description
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 2024, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Cash Flows, (v) related notes to these financial statements and (vi) document and entity information
	104	Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document contained in Exhibit 101)

(A) Provided herein in electronic format as an exhibit.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FirstEnergy has not filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

July 30, 2024

FIRSTENERGY CORP.

Registrant

/s/ Jason J. Lisowski

Jason J. Lisowski

Vice President, Controller and Chief Accounting Officer 

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