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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)
    ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the FISCAL YEAR ended December 31, 2023

OR

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

For the transition period from ___________________ to ___________________
FE Logo.jpg
CommissionRegistrant; State of Incorporation;I.R.S. Employer
File NumberAddress; and Telephone NumberIdentification No.
 
333-21011FIRSTENERGY CORP34-1843785
 (AnOhioCorporation) 
   76 South Main Street 
 AkronOH44308 
 Telephone(800)736-3402 
   
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each ClassTrading SymbolName of Each Exchange on Which Registered
Common Stock, $0.10 par value per shareFENew York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
 ☑
No
 ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes☐No☑
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes☐No☑
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.
$22,261,707,443 as of June 30, 2023
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:
CLASSAS OF JANUARY 31, 2024
Common Stock, $0.10 par value574,440,850 
Documents Incorporated By Reference
 PART OF FORM 10-K INTO WHICH
DOCUMENTDOCUMENT IS INCORPORATED
Portions of the Definitive Proxy Statement for the 2024 Annual Meeting of Shareholders of FirstEnergy Corp. to be held May 22, 2024.Part III




TABLE OF CONTENTS
 Page
Glossary of Terms
Part I 
Item 1. Business
The Companies
Capital Requirements
Supply Plan
System Demand
Regional Reliability
Competition
Seasonality
Human Capital
Information About Our Executive Officers
FirstEnergy Website and Other Social Media Sites and Applications
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 1C. Cybersecurity
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. [Reserved]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Financial Statements
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
i

Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Part IV
Item 15. Exhibit and Financial Statement Schedules
Item 16. Form 10-K Summary
ii

GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
AE SupplyAllegheny Energy Supply Company, LLC, an unregulated generation subsidiary of FE
AGCAllegheny Generating Company, a generation subsidiary of MP
ATSIAmerican Transmission Systems, Incorporated, a transmission subsidiary of FET
CEIThe Cleveland Electric Illuminating Company, an Ohio electric utility subsidiary of FE
FEFirstEnergy Corp., a public utility holding company
FENOCEnergy Harbor Nuclear Corp. (formerly known as FirstEnergy Nuclear Operating Company), a subsidiary of EH, which operates EH’s nuclear generating facilities
FE PAFirstEnergy Pennsylvania Electric Company, a Pennsylvania electric utility subsidiary of FirstEnergy Pennsylvania Holding Company LLC, a wholly owned subsidiary of FE
FESEnergy Harbor LLC (formerly known as FirstEnergy Solutions Corp.), a subsidiary of EH, which provides energy-related products and services
FESCFirstEnergy Service Company, which provides legal, financial, and other corporate support services
FES DebtorsFENOC, FES, and FES’ subsidiaries as of March 31, 2018
FETFirstEnergy Transmission, LLC a consolidated VIE of FE, and the parent company of ATSI, MAIT and TrAIL, and having a joint venture in PATH
FEVFirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FirstEnergyFirstEnergy Corp., together with its consolidated subsidiaries
Global HoldingGlobal Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC
JCP&LJersey Central Power & Light Company, a New Jersey electric utility subsidiary of FE
KATCoKeystone Appalachian Transmission Company, a transmission subsidiary of FE
MAITMid-Atlantic Interstate Transmission, LLC, a transmission subsidiary of FET
MEMetropolitan Edison Company, a former Pennsylvania electric utility subsidiary of FE, which merged with and into FE PA on January 1, 2024
MPMonongahela Power Company, a West Virginia electric utility subsidiary of FE
OEOhio Edison Company, an Ohio electric utility subsidiary of FE
Ohio CompaniesCEI, OE and TE
PATHPotomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH-AlleghenyPATH Allegheny Transmission Company, LLC
PATH-WVPATH West Virginia Transmission Company, LLC
PEThe Potomac Edison Company, a Maryland and West Virginia electric utility subsidiary of FE
PennPennsylvania Power Company, a former Pennsylvania electric utility subsidiary of OE, which merged with and into FE PA on January 1, 2024
Pennsylvania CompaniesME, PN, Penn and WP, each of which merged with and into FE PA on January 1, 2024
PNPennsylvania Electric Company, a former Pennsylvania electric utility subsidiary of FE, which merged with and into FE PA on January 1, 2024
Signal PeakSignal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana
TEThe Toledo Edison Company, an Ohio electric utility subsidiary of FE
TrAILTrans-Allegheny Interstate Line Company, a transmission subsidiary of FET
Transmission CompaniesATSI, KATCo, MAIT and TrAIL
UtilitiesOE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
WPWest Penn Power Company, a former Pennsylvania electric utility subsidiary of FE, which merged with and into FE PA on January 1, 2024

iii

The following abbreviations and acronyms are used to identify frequently used terms in this report:
2021 Credit FacilitiesCollectively, the six separate senior unsecured five-year syndicated revolving credit facilities entered into by FE, the Utilities and the Transmission Companies, on October 18, 2021, as amended through October 20, 2023
2023 Credit FacilitiesCollectively, the FET Revolving Facility and KATCo Revolving Facility
2026 Convertible NotesFE's 4.00% convertible senior notes, due 2026
2031 NotesFE’s 7.375% Notes, Series C, due 2031
A&R FET LLC
Agreement		Fourth Amended and Restated Limited Liability Company Operating Agreement of FET
ACEAffordable Clean Energy
AEPAmerican Electric Power Company, Inc.
AFSAvailable-for-sale
AFSIAdjusted Financial Statement Income
AFUDCAllowance for Funds Used During Construction
AMIAdvanced Metering Infrastructure
AMTAlternative Minimum Tax
AOCIAccumulated Other Comprehensive Income (Loss)
AROAsset Retirement Obligation
ASCAccounting Standards Codification
ASUAccounting Standards Update
Bankruptcy CourtU.S. Bankruptcy Court in the Northern District of Ohio in Akron
BGSBasic Generation Service
BrookfieldNorth American Transmission Company II L.P., a controlled investment vehicle entity of Brookfield Infrastructure Partners
Brookfield GuarantorsBrookfield Super-Core Infrastructure Partners L.P., Brookfield Super-Core Infrastructure Partners (NUS) L.P., and Brookfield Super-Core Infrastructure Partners (ER) SCSp
CAAClean Air Act
CCRCoal Combustion Residual
CERCLAComprehensive Environmental Response, Compensation, and Liability Act of 1980
CFIUSCommittee on Foreign Investments in the United States
CFRCode of Federal Regulations
CISOChief Information Security Officer
CO2
Carbon Dioxide
COVID-19Coronavirus disease
CPPEPA's Clean Power Plan
CSAPRCross-State Air Pollution Rule
CTAConsolidated Tax Adjustment
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DCPDFE Deferred Compensation Plan for Outside Directors
DCRDelivery Capital Recovery
DEIDiversity, Equity and Inclusion
DMRDistribution Modernization Rider
DPADeferred Prosecution Agreement entered into on July 21, 2021 between FE and the U.S. Attorney’s Office for the S.D. Ohio
DSICDistribution System Improvement Charge
EDCElectric Distribution Company
EDCPFE Amended and Restated Executive Deferred Compensation Plan
EDISElectric Distribution Investment Surcharge
EE&CEnergy Efficiency and Conservation
EEIThe Edison Electric Institute
EESGEmployee, Environmental, Social and Corporate Governance
iv

EGSElectric Generation Supplier
EGUElectric Generation Unit
EHEnergy Harbor Corp.
ELGEffluent Limitation Guidelines
EmPOWER MarylandEmPOWER Maryland Energy Efficiency Act
ENECExpanded Net Energy Cost
Energize365FirstEnergy's Transmission and Distribution Infrastructure Investment Program.
EnergizeNJJCP&L's second Infrastructure Investment Program
EPAUnited States Environmental Protection Agency
EPSEarnings per Share
ESP IVElectric Security Plan IV
ESP VElectric Security Plan V
Exchange Act
Securities and Exchange Act of 1934, as amended
FASBFinancial Accounting Standards Board
FE BoardFE Board of Directors
FE Revolving FacilityFE and the Utilities’ former five-year syndicated revolving credit facility, as amended, and replaced by the 2021 Credit Facilities on October 18, 2021
FERCFederal Energy Regulatory Commission
FET BoardFET Board of Directors
FET LLC AgreementThird Amended and Restated Limited Liability Company Operating Agreement of FET
FET Minority Equity Interest SaleSale of an additional 30% membership interest of FET, such that Brookfield will own 49.9% of FET
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 FacilityFET’s five-year syndicated revolving credit facility, dated as of October 20, 2023
FitchFitch Ratings Service
FMBFirst Mortgage Bond
FTRFinancial Transmission Right
GAAPGenerally Accepted Accounting Principles in the United States of America
GHGGreenhouse Gas
HB 6House Bill 6, as passed by Ohio's 133rd General Assembly
IBEWInternational Brotherhood of Electrical Workers
ICP 2015FirstEnergy Corp. 2015 Incentive Compensation Plan
ICP 2020FirstEnergy Corp. 2020 Incentive Compensation Plan
IRA of 2022Inflation Reduction Act of 2022
IRSInternal Revenue Service
KATCo Revolving FacilityKATCo’s four-year syndicated revolving credit facility, dated as of October 20, 2023
kVKilovolt
kWhKilowatt-hour
LOCLetter of Credit
LTIIPLong-Term Infrastructure Improvement Plan
MDPSCMaryland Public Service Commission
MGPManufactured Gas Plants
Moody’sMoody’s Investors Service, Inc.
MWMegawatt
MWhMegawatt-hour
NAVNet Asset Value
NCINoncontrolling Interest
v

N.D. OhioFederal District Court, Northern District of Ohio
NERCNorth American Electric Reliability Corporation
NJBPUNew Jersey Board of Public Utilities
NOLNet Operating Loss
NOxNitrogen Oxide
NSRNew Source Review
NUGNon-Utility Generation
NYPSCNew York State Public Service Commission
OAGOhio Attorney General
OCCOhio Consumers' Counsel
ODSAOhio Development Service Agency
Ohio StipulationStipulation and Recommendation, dated November 1, 2021, entered into by and among the Ohio Companies, the OCC, PUCO Staff, and several other signatories
OOCICOhio Organized Crime Investigations Commission, which is composed of members of the Ohio law enforcement community and is chaired by the OAG
OPEBOther Postemployment Benefits
OPEIUOffice and Professional Employees International Union
OSMREUnited States Department of the Interior, Office of Surface Mining Reclamation and Enforcement
OVECOhio Valley Electric Corporation
PA ConsolidationConsolidation of the Pennsylvania Companies
PEERFirstEnergy's Program for Enhanced Employee Retirement
PJMPJM Interconnection, LLC, an RTO
PJM RegionThe territory that PJM coordinates the movement of electricity through, including all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
PJM TariffPJM Open Access Transmission Tariff
POLRProvider of Last Resort
PPAPurchase Power Agreement
PPUCPennsylvania Public Utility Commission
PUCOPublic Utilities Commission of Ohio
Regulation FDRegulation Fair Disclosure promulgated by the SEC
RFCReliabilityFirst Corporation
ROEReturn on Equity
RTORegional Transmission Organization
S.D. OhioFederal District Court, Southern District of Ohio
SECUnited States Securities and Exchange Commission
SEETSignificantly Excessive Earnings Test
SIPState Implementation Plan(s) under the CAA
SLCSpecial Litigation Committee of the FE Board
SO2
Sulfur Dioxide
SOFRSecured Overnight Financing Rate
SOSStandard Offer Service
SPESpecial Purpose Entity
SSOStandard Service Offer
S&PStandard & Poor’s Ratings Service
S&P 500Standard & Poor’s 500 index
Tax ActTax Cuts and Jobs Act adopted December 22, 2017
UWUAUtility Workers Union of America
VEPCOVirginia Electric and Power Company
VIEVariable Interest Entity
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VSCCVirginia State Corporation Commission
WVPSCPublic Service Commission of West Virginia
vii

PART I
ITEM 1.     BUSINESS
The Companies

FE and its subsidiaries are principally involved in the transmission, distribution, and generation of electricity. FirstEnergy’s utility operating companies comprise one of the nation’s largest investor-owned electric systems, serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include more than 24,000 miles of transmission lines and two regional transmission operation centers. AGC and MP control 3,580 MWs of total capacity.
FirstEnergy’s revenues are derived primarily from electric service provided by the Utilities and Transmission Companies, which were reported under two operating segments: Regulated Distribution and Regulated Transmission.

Regulated Utility Operating Subsidiaries

The Utilities’ combined service areas encompass approximately 65,000 square miles in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey, and New York. The areas they serve have a combined population of approximately 14 million. The Utilities' serve approximately 6.2 million customers with a rate base of approximately $27.3 billion. On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, making FE PA a new, single operating entity. In addition to merging each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies, (i) WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and (ii) PN and ME contributed their respective Class B equity interests of MAIT to FE. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and serves an area with a population of approximately 4.5 million. FE PA operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.

OE owns property and does business as an electric public utility in Ohio, providing distribution services to approximately 1.1 million customers in central and northeastern Ohio, with a rate base of $2.1 billion. OE has 1,056 employees and serves an area that has a population of approximately 2.3 million.

Penn, a former subsidiary of OE, owned property and conducted business as an electric public utility in Pennsylvania, providing distribution services to approximately 0.2 million customers in western Pennsylvania, with a rate base of $0.6 billion. Penn had 179 employees and served an area that had a population of approximately 0.4 million. On January 1, 2024, Penn merged with and into FE PA.

CEI owns property and does business as an electric public utility in Ohio, providing distribution services to approximately 0.8 million customers in northeastern Ohio, with a rate base of $1.7 billion. CEI has 829 employees and serves an area that has a population of approximately 1.6 million.

TE owns property and does business as an electric public utility in Ohio, providing distribution services to approximately 0.3 million customers in northwestern Ohio, with a rate base of $0.5 billion. TE has 328 employees and serves an area that has a population of approximately 0.7 million.

JCP&L owns property and does business as an electric public utility in New Jersey, providing distribution services to approximately 1.2 million customers, as well as transmission services in northern, western, and east central New Jersey, with a combined rate base of $4.2 billion. JCP&L has 1,328 employees and serves an area that has a population of approximately 2.8 million.

ME owned property and conducted business as an electric public utility in Pennsylvania, providing distribution services to approximately 0.6 million customers in eastern and south central Pennsylvania, with a rate base of $2.0 billion. ME had 591 employees and served an area that had a population of approximately 1.3 million. On January 1, 2024, ME merged with and into FE PA.

PN owned property and conducted business as an electric public utility in Pennsylvania, providing distribution services to approximately 0.6 million customers in western, northern, and south-central Pennsylvania, and western New York, with a rate base of $2.1 billion. PN had 713 employees and served an area that had a population of approximately 1.2 million in Pennsylvania and approximately 4,000 in New York. On January 1, 2024, PN merged with and into FE PA.

PE owns property and does business as an electric public utility in Maryland, Virginia, and West Virginia, providing distribution services to approximately 0.4 million customers in Maryland and West Virginia and provides transmission services in Maryland, West Virginia and Virginia, with a combined rate base of approximately $1.4 billion. PE has 512 employees and serves an area that has a population of approximately 1.0 million.

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MP owns property and does business as an electric public utility in West Virginia, providing distribution services to approximately 0.4 million customers, as well as generation and transmission services in northern West Virginia, with a combined rate base of $3.1 billion. MP has 1,004 employees and serves an area with a population of approximately 0.8 million. MP is contractually obligated to provide power to PE to meet its load obligations in West Virginia. MP owns or contractually controls 3,580 MWs of generation capacity that is supplied to its electric utility business, including a 16.25% undivided interest in the Bath County pumped-storage hydroelectric generation facility in Virginia (487 MWs) through its wholly owned subsidiary AGC.

WP owned property and conducted business as an electric public utility in Pennsylvania, providing distribution services to approximately 0.7 million customers, as well as transmission services in southwestern, south-central, and northern Pennsylvania, with a combined rate base of $2.3 billion. WP had 634 employees and served an area with a population of approximately 1.6 million. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo before merging with and into FE PA.

Regulated Transmission Operating Subsidiaries

FET, the parent of ATSI, MAIT, PATH, and TrAIL, is a subsidiary of FE which holds 80.1% of its issued and outstanding membership interests. Brookfield owns the remaining 19.9% of the issued and outstanding membership interests of FET. Through its subsidiaries, FET owns and operates high-voltage transmission facilities in the PJM Region. FET's subsidiaries are subject to regulation by FERC and applicable state regulatory authorities.

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 majority of the purchase price is expected to be paid in cash upon closing, and the remainder will be payable by the issuance of a promissory note, which is expected to be repaid by the end of 2024. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the PPUC. In addition, pursuant to the FET P&SA II, FirstEnergy made the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

ATSI owns high-voltage transmission facilities in PJM, which consist of approximately 7,900 circuit miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV in Ohio and Pennsylvania and has a rate base of $3.8 billion.

TrAIL owns high-voltage transmission facilities in PJM, which consists of approximately 260 circuit miles of transmission lines, including a 500 kV transmission line extending approximately 150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection with VEPCO in northern Virginia, and has a rate base of $1.4 billion.

MAIT owns high-voltage transmission facilities in PJM, which consist of approximately 4,300 circuit miles of transmission lines with nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV, 115 kV, 69 kV and 46 kV in Pennsylvania, and has a rate base of $2.1 billion.

KATCo was formed to accommodate new transmission construction in the WP, MP and PE footprint and did not own or operate any transmission assets as of December 31, 2023. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.

Service Company

FESC provides corporate support and other services, including executive administration, accounting and finance, risk management, human resources, corporate affairs, communications, information technology, legal services and other similar services at cost, in accordance with its cost allocation manual, to affiliated FirstEnergy companies under FESC agreements.

Operating Segments

FirstEnergy's reportable operating segments are comprised of the Regulated Distribution and Regulated Transmission segments.

The Regulated Distribution segment distributes electricity through FirstEnergy’s utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey, and Maryland. This segment also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are derived from primarily forward-looking formula rates, pursuant to which the
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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. As described above, Brookfield holds 19.9% of the issued and outstanding membership interests of FET and has entered into an agreement to purchase from FE, an incremental 30% equity interest in FET, such that Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1%. The transaction is subject to customary closing conditions, including PPUC approval, and is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

Corporate/Other reflects corporate support and other costs not charged or attributable to the Utilities 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 elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2023, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2023, Corporate/Other had approximately $7.1 billion of external FE holding company debt.

In 2024, FirstEnergy changed its reportable segments to include the following:
•Distribution Segment, which will consist of the Ohio Companies and FE PA;
•Integrated Segment, which will consist of MP, PE and JCP&L; and
•Stand-Alone Transmission Segment, which will consist of FE's ownership in FET and KATCo.

On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo. Corporate/Other will continue to reflect corporate support and other support costs not charged or attributable to the Utilities 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.
Regulatory Accounting

FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies as their rates are established by a third-party regulator with the authority to set binding rates that are cost-based and can be charged to and collected from customers.

The Utilities and the Transmission Companies recognize, as regulatory assets and regulatory liabilities, costs that FERC and the various state utility commissions, as applicable, have authorized for recovery from or return to customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets and regulatory liabilities would have been charged or credited to income as incurred. All regulatory assets and liabilities are expected to be recovered from or returned to customers. Based on current ratemaking procedures, the Utilities and the Transmission Companies continue to collect cost-based rates for their distribution and transmission services; accordingly, it is appropriate that the Utilities and the Transmission Companies continue the application of regulatory accounting to those operations. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded regulatory assets and liabilities are removed from the balance sheet in accordance with GAAP.
State Regulation
The following table summarizes the allowed regulated distribution ROE and the aggregate actual ROE of the Utilities by state as determined for regulatory purposes as of December 31, 2023:
StateAllowed ROEActual ROE
Maryland9.5%4.7%
New Jersey
9.6% settled
4.1%(1)
Ohio10.5%5.8%
Pennsylvania
Settled(2)
9.2%
West Virginia
Settled(2)
7.7%(3)
(1) As updated in pending rate case.
(2) Commission-approved settlement agreement did not disclose ROE rates.
(3) As filed in pending rate case and includes generation and transmission.
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See "Outlook - State Regulation" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Federal Regulation
See "Outlook - FERC Regulatory Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Environmental Matters
See "Outlook - Environmental Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Capital Requirements

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. See "Capital Resources and Liquidity" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.

Supply Plan

Supply Chain

Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressures, have increased costs and decreased the availability of certain materials, equipment, and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results, including operations, cash flow and financial condition. FirstEnergy continues to monitor supply chain risk as it anticipates these challenges continuing into 2024, and is mitigating these risks by:

•Utilizing a cross-functional team to forecast potential impacts to operations and programs;
•Expanding supply base to increase resiliency;
•Enhancing the demand management and material reservation process;
•Evaluating substitute products, reserving production capacity, and buying ahead in targeted categories; and
•Participating in discussions and initiatives with other utilities through EEI, which has a long history of mutual assistance in the electric utility industry.

Default Service

Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. These default service plans vary by state and service territory, and volume of sales can vary depending on the level of shopping that occurs. JCP&L’s default service, or BGS supply, is secured through a statewide competitive procurement process approved by the NJBPU. Default service for the Ohio Companies, Pennsylvania Companies and PE's Maryland jurisdiction are provided through a competitive procurement process approved by the PUCO (under ESP IV), PPUC (under the Default Service Plan) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as the default Load Serving Entity. West Virginia electric generation continues to be regulated by the WVPSC.

Fuel Supply

MP currently has coal contracts with various terms to purchase approximately 6.1 million tons of coal for the year 2024, which, along with its 2023 year-end inventory levels, accounts for all of its forecasted 2024 coal requirements. MP has the ability to acquire additional tonnage through options available in its current contracts, as well as purchases through the spot market. The contracts expire at various times through 2025. This contracted coal is produced primarily from mines located in Pennsylvania, Illinois and West Virginia. In order to meet emission requirements, MP holds contracts for a variety of reagents expiring at various times through 2026, as well as the ability to purchase additional reagents through the spot market. Additionally, MP is granted emission allowances by the EPA and purchases additional allowances as needed to meet emission requirements. See "Outlook - Environmental Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information pertaining to the impact of increased environmental regulations on fuel supply.

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System Demand
The maximum hourly demand for each of the Utilities was:
For the Years Ended December 31,
System Demand202320222021
(In MWs)
CEI3,868 4,266 4,253 
JCP&L5,731 6,122 5,902 
ME2,890 3,021 2,976 
MP2,051 2,124 2,114 
OE5,192 5,652 5,598 
PE3,103 3,514 2,905 
Penn900 944 889 
PN2,763 2,838 2,908 
TE2,220 2,277 2,265 
WP3,706 3,827 3,827 

Regional Reliability

All of FirstEnergy's facilities are located within the PJM Region and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of NERC in accordance with a delegation agreement approved by FERC.

Competition

Within FirstEnergy’s Regulated Distribution segment, generally there is no competition for electric distribution service in the Utilities’ respective service territories in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. Additionally, there has traditionally been no competition for transmission service in the PJM Region. However, pursuant to FERC’s Order No. 1000 and subject to state and local siting and permitting approvals, non-incumbent developers now can compete for certain PJM transmission projects in the service territories of FirstEnergy’s Regulated Transmission segment. This could result in additional competition to build transmission facilities in the Regulated Transmission segment’s service territories while also allowing the Regulated Transmission segment the opportunity to seek to build facilities in non-incumbent service territories.

Seasonality

The sale of electric power is generally a seasonal business, and weather patterns can have a material impact on FirstEnergy’s Regulated Distribution segment operating results. Demand for electricity in our service territories historically peaks during the summer and winter months. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower revenue, earnings and cash flow.

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Human Capital

FirstEnergy focuses on a number of human capital resources, measures and objectives in managing its business, including: integrity, safety, DEI, workplace flexibility, employee development and compensation and benefits. During 2023, FirstEnergy continued to enhance its dedicated focus on employees by providing employees with additional opportunities to improve belonging, inclusion and engagement within our workforce.

Employees and Collective Bargaining Agreements

As of December 31, 2023, FirstEnergy had 12,042 employees, all of whom were located in the United States as follows:
Total
Employees		Bargaining
Unit
Employees
FESC4,868 453 
CEI829 566 
JCP&L1,328 1,026 
ME(1)
591 451 
MP1,004 379 
OE1,056 642 
PE512 251 
Penn(1)
179 129 
PN(1)
713 489 
TE328 233 
WP(1)
634 477 
Total12,042 5,096 
(1) On January 1, 2024, employees of the Pennsylvania Companies became employees of FE PA as discussed further above.

As of December 31, 2023, the IBEW, the UWUA and the OPEIU unions collectively represented approximately 45% of FirstEnergy’s employees. There are 15 collective bargaining agreements between FirstEnergy’s subsidiaries and its unions, which have three, four or five-year terms. In 2023, FirstEnergy’s subsidiaries reached new agreements with two IBEW locals, covering 482 employees, and one UWUA local, covering 821 employees. Additionally, in 2023, FirstEnergy’s subsidiaries extended the agreements of two IBEW locals, covering 263 employees and five UWUA locals, covering 1,305 employees.

Safety

Safety is a core value of FirstEnergy. FirstEnergy employees have the power and responsibility to keep each other safe and eliminate life-changing events, which are injuries that have life-changing impacts or fatal results. Safety metrics, such as injuries that result in days away or restricted time and life-changing events, are regularly monitored, internally reported, and are included in the annual incentive compensation program to reinforce that a safe work environment is crucial to FirstEnergy’s success.

FirstEnergy continues to focus on mitigating life-changing event exposure to strengthen FirstEnergy’s safety-first culture and drive safer decisions from an engaged workforce who puts safety first. FirstEnergy continues to embed its "Leading with Safety" learnings and experiences and continues to enhance and reinforce leader and employee safety training and exposure control concepts to improve job site exposure identification, communication and mitigation to prevent life changing events. Further, FirstEnergy continues to expand its “Leading with Safety” experiences with its employees to achieve excellence in personal, contractor and public safety.

Diversity, Equity and Inclusion

DEI is a core value, as well as a corporate objective because a diverse, equitable and inclusive work environment delivers better service to customers, strong operational performance, innovation, and a safe, rewarding work experience for employees. FirstEnergy is focused on building a diverse workforce for the future, advancing a culture of equity, inclusion and belonging, and enhancing our diversity focus with our customers, in our communities and with our suppliers.

Affirmative steps taken at FirstEnergy to promote the core value of DEI include:
•FirstEnergy sponsors an executive DEI council consisting of senior management and other leaders across the company;
•Conducted “Employee Engagement Survey” to capture employees’ perspectives on their work experience and progress toward embracing a more inclusive culture. The survey results are discussed with employees in order to drive initiatives and action plans for improvement. This includes:
•a cross-functional working group to oversee the development and implementation of DEI action plans company-wide;
•additional teams of employees embedded throughout FirstEnergy to implement local actions supporting DEI;
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•FirstEnergy’s employees have established multiple employee business resource groups, known as "EBRGs," to further support DEI objectives through networking, mentoring, coaching, recruiting, development and community outreach;
•Employees are provided ongoing training and education on a variety of DEI topics;
•Enhanced transparency of DEI data, and talent processes;
•Enhancements to the recruiting processes to increase the number of diverse candidates considered for open positions and expand the diversity of teams interviewing those candidates. These enhancements include:
▪expanded relationship building with key diverse professional organizations, colleges and universities through the FirstEnergy Ambassador Network;
▪a more strategic approach to proactive talent sourcing in an effort to increase diversity of candidate slates presented to hiring managers;
▪expanded diversity of teams interviewing those candidates.
•FirstEnergy has increased leadership accountability through the continuation of including DEI metrics in FirstEnergy’s annual incentive compensation program.

Workplace Flexibility

FirstEnergy is committed to supporting employees’ work/life balance by providing flexible work arrangements for many of its employees and encouraging career growth as well as personal balance. In the fall of 2022, FirstEnergy formally adopted guidelines to facilitate flexible work arrangements for eligible full-time and part-time non-bargaining employees. Flexible work arrangements, such as permitting certain employees to work from alternate locations or to begin and end work at variable times, offer a variety of approaches to the way employees work. As part of this commitment, FirstEnergy has begun an implementation of a facility optimization strategy, in which we are reducing the number of office buildings based on the number of employees that are mobile and work from home. These approaches can help employees achieve their priorities and meet customer and business needs while promoting enhanced convenience and balance between work and personal commitments.

Employee Development

FirstEnergy’s employees are empowered to take ownership of their careers with increased openness into FirstEnergy’s internal and external hiring process and greater availability of tools and processes that support career management, talent reviews, succession planning and leadership selection. FirstEnergy is committed to preparing its high-performing workforce for the future and helping employees reach their full potential, which includes developing employee skills and competencies and preparing aspiring, emerging and experienced leaders for future leadership responsibilities.

Understanding FirstEnergy’s rapidly changing industry and strategy is key to its employees’ ability to support FirstEnergy’s mission and meet its customers’ evolving needs. Key FirstEnergy development programs include:
•a mentoring program;
•new supervisor and manager development program;
•experienced leader program;
•aspiring leader program;
•external partnership with the Center for Creative Leadership® and BeingFirst® for senior and executive leadership development,
•"Educate to Elevate," which provides access to post-secondary education and a path to both Associate’s and Bachelor’s degrees for employees; and
•an apprentice line worker program designed to attract technical entry-level talent to FirstEnergy.

Compensation and Benefits

FirstEnergy’s total rewards program is designed to attract, motivate, retain and reward employees for their role in the success of FirstEnergy. The base pay program is designed to provide individual base pay levels that balance an employee’s value to FirstEnergy with comparable jobs at peer companies. FirstEnergy aims to ensure that its internal policies and processes support pay equity, which was confirmed in a third-party review of practices in 2019 and continues to be part of the normal ongoing process. The annual incentive compensation program is designed to reward the achievement of near-term corporate and business unit objectives, as well as outstanding individual performance. Additionally, FirstEnergy’s long-term incentive compensation program is designed to reward eligible leaders for FirstEnergy’s achievement of longer-term goals intended to drive shareholder value and growth. In addition to base pay and incentive compensation plans, FirstEnergy offers a comprehensive benefits program, including a 401(k) savings plan and a defined benefit pension plan to eligible employees.
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Information About Our Executive Officers (as of February 13, 2024)
NameAgePositions Held During Past Five YearsDates
Brian X. Tierney56President and Chief Executive Officer (A) (B)2023-Present
Blackstone Infrastructure Partners, Senior Managing Director2021-2023
AEP, Executive Vice President - Strategy2021
AEP, Executive Vice President and Chief Financial Officer*-2020
Christine L. Walker58Senior Vice President, Chief Human Resources Officer and Corporate Services (B)2021-Present
Senior Vice President and Chief Human Resources Officer (B)2019-2021
Vice President, Human Resources (B)*-2019
Hyun Park62Senior Vice President and Chief Legal Officer (A) (B)2021-Present
Senior Vice President and General Counsel (C) (D) (E)2021-2022
LimNexus, Partner and General Counsel2019-2021
Latham & Watkins, Of Counsel*-2019
Jason J. Lisowski42Vice President, Controller and Chief Accounting Officer (A) (B)*-Present
Vice President and Controller (C) (E) (F)*-Present
K. Jon Taylor50Senior Vice President, Chief Financial Officer and Strategy (A) (B)2021-Present
Senior Vice President and Chief Financial Officer (C) (E) (F)2020-Present
Senior Vice President and Chief Financial Officer (A) (B)2020-2021
Vice President, Utility Operations (B)2019-2020
President (D)2019-2020
President, Ohio Operations (B)*-2019
Vice President (C) *-2019
Toby L. Thomas52Chief Operating Officer (A) (B)2023-Present
AEP, Senior Vice President2021-2023
Indiana Michigan Power, President and Chief Operating Officer*-2021
A. Wade Smith59President, FirstEnergy Utilities (A) (B)2023-Present
Puget Sound Energy, Inc., Executive Vice President and Chief Operating Officer2022-2023
Pacific Gas & Electric, Senior Vice President2021-2022
AEP, Senior Vice President*-2021
* Indicates position held at least since January 1, 2019
(A) Denotes position held at FE
(B) Denotes position held at FESC
(C) Denotes position held at the Ohio Companies, the Pennsylvania Companies(1), MP, PE, FET, KATCo, TrAIL and ATSI
(D) Denotes position held at AGC
(E) Denotes position held at MAIT
(F) Denotes position held at FE PA(1)
(1) On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity. Upon consolidation, current executive officers of the Pennsylvania Companies were named executive officers of FE PA.
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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 the 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 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.

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ITEM 1A.     RISK FACTORS

We operate in a business environment that involves significant risks, many of which are beyond our control. Management regularly evaluates the most significant risks of its businesses and reviews those risks with the FE Board and appropriate Committees of the FE Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we consider material. The risks that we face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our business, financial condition, results of operations, liquidity or cash flows. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. These risk factors should be read in conjunction with Item 1, "Business,” Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business, financial condition, results of operations, liquidity or cash flows.

Risks Associated with Damage to Our Reputation and HB 6 Related Litigation and Investigations

Damage to our reputation may arise from numerous sources making us vulnerable to negative customer perception, adverse regulatory outcomes, or other consequences, which could materially adversely affect our business, results of operations, and financial condition.

Our reputation is important. Damage to our reputation could materially adversely affect our business, results of operations, and financial condition and may arise from numerous sources further discussed below, including a breach of the DPA, negative outcomes associated with the SEC investigation or other HB 6 litigation or investigations, a significant cyber-attack, data security or physical security breach, failure to provide safe and reliable service, and negative perceptions regarding the operation of coal-fired generation, particularly GHG emissions. Any damage to our reputation may lead to negative customer perception, which may make it difficult for us to compete successfully for new opportunities, or could adversely impact our ability to launch new sophisticated technology-driven solutions to meet our customer expectations. A damaged reputation could further result in FERC, the PUCO, and other regulatory and legislative authorities being less likely to view us in a favorable light, and could negatively impact the rates we charge customers or otherwise cause us to be susceptible to unfavorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements. See "Risks Associated with Climate Change, GHG Emission and Other Environmental Matters" below.

If we violate our DPA that we entered into on July 20, 2021, it could have a material adverse effect on our reputation, consolidated financial statements, and our ability to access capital and our liquidity.

On July 21, 2021, we entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the previously disclosed U.S. Attorney’s Office investigation into us relating to our lobbying and governmental affairs activities concerning HB 6. Under the DPA, the U.S. Attorney’s Office filed a single charge alleging that we conspired to commit honest services wire fraud. The DPA provides that the U.S. Attorney’s Office will defer any prosecution of such conspiracy charge and any other criminal or civil case against us in connection with the matters identified therein for a three-year period subject to certain obligations of ours, including, but not limited to, the following: (i) continued cooperation 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) payment of a criminal monetary penalty totaling $230 million; (iii) publication 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 updating of the same on a quarterly basis during the term of the DPA; (iv) publication of a public acknowledgement of our conduct, including a statement, as dictated in the DPA, regarding our use of 501(c)(4) entities; and (v) continued implementation and review of our 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. If we are found to have breached the terms of the DPA, the U.S. Attorney’s Office may elect to prosecute, or bring a civil action against, us for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have a material adverse impact on our reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as our consolidated financial statements. Failure to comply with the DPA, including alleged failures to comply with anti-corruption and anti-bribery laws, may also result in a breach of certain covenants contained in our credit agreements and could result in an event of default under such agreements, and we would not be able to access our credit facilities for additional borrowings and letters of credit during the existence of any such default.

The SEC investigation and HB 6 related litigation could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.

Following the announcement by the U.S. Attorney’s Office for the S.D. Ohio of the investigation surrounding HB 6 in July 2020, certain of our stockholders and customers filed several lawsuits against us and certain current and former directors, officers and other employees, including the federal securities class action litigation In re FirstEnergy Corp. Securities Litigation (Federal District Court, S.D. Ohio). The investigations and litigation related to HB 6 could divert management’s focus and have resulted in, and could continue to result in substantial investigation expenses, and the commitment of substantial corporate resources. The
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outcome, duration, scope, result or related costs of the investigations and related litigation of the government investigations, particularly the SEC investigation and the securities class action lawsuit discussed below, are inherently uncertain. Therefore, any of these risks could impact us significantly beyond expectations. See Note 14, "Commitments, Guarantees and Contingencies" of the Notes to Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates.” Moreover, we are unable to predict the potential for any additional investigations or litigation, any of which could exacerbate these risks or expose us to potential criminal or civil liabilities, sanctions or other remedial measures, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.

On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FirstEnergy, and on September 1, 2020, issued subpoenas to FirstEnergy and certain of its officers. We continue to cooperate with the SEC in their ongoing investigation. We believe that it is probable that FE will incur a loss in connection with the resolution of the SEC’s investigation. Given the ongoing nature and complexity of such investigation, we cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation, but such resolution could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.

We also believe that it is probable that FE will incur a loss in connection with the resolution of In re FirstEnergy Corp. Securities Litigation. Given the ongoing nature and complexity of such litigation, we cannot yet reasonably estimate a loss or range of loss that may arise from its resolution. However, if it is resolved against us substantial monetary damages could result and our reputation, business, financial condition, results of operations, liquidity or cash flows may be materially adversely affected.

These matters are likely to continue to have an adverse impact on the trading prices of our securities, which could be material. See Note 14, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements, for additional details on the government investigations and subsequent litigation surrounding HB 6.

The HB 6 related state regulatory investigations could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.

There are several state regulatory matters associated with the ongoing governmental investigations including, but not limited to, the following:

•On August 10, 2023, the U.S. Attorney for the Southern District of Ohio requested for the third time that the PUCO stay the below pending HB 6-related matters for a period of six additional months, which was approved by the PUCO on August 23, 2023. On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing, and on November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing:
▪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.
▪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.
▪On December 30, 2020, the PUCO 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. The auditor’s report was filed on January 14, 2022, and the parties submitted final comments and responses in the second quarter 2022. See ”Outlook – Ohio” below for additional information regarding the auditor’s findings.
•On March 10, 2021, the PUCO expanded the scope of an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020 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 Rider DCR or through an alternative proceeding.

While FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway, FirstEnergy shareholders in particular are at risk of being adversely impacted because the rates our Utilities and Transmission Companies are allowed to charge may be decreased as a result of actions taken by a regulator to which our Utilities and Transmission Companies are subject to jurisdiction, whether as a result of the DPA, any failure to have complied with anti-corruption laws, or otherwise.

We are unable to predict the adverse impacts of such regulatory matters, including with respect to rates, and, therefore, any of these risks could impact us significantly beyond expectations. Moreover, we are unable to predict the potential for any additional regulatory actions, any of which could exacerbate these risks or expose us to adverse outcomes in pending or future rate cases, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.

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Risks Associated with the Execution of Our Strategic Initiatives

The inability to close the FET minority equity interest sale to Brookfield announced in February 2023 may have material adverse effects on our cash flows, liquidity and financial condition.

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 majority of the purchase price is expected to be paid in cash upon closing, and the remainder will be payable by the issuance of secured promissory notes, which is expected to be repaid by the end of 2024. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the PPUC The FET Minority Equity Interest Sale is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

This transaction involves various inherent risks, such as our ability to obtain the necessary regulatory and other approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; and our ability to realize the benefits expected from the transaction. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from this transaction. Our failure to consummate this transaction in a timely manner, including satisfying all closing conditions, could have material adverse effects on our cash flows, liquidity and financial condition.

Risks Associated with Regulation of Our Distribution and Transmission Businesses

Our ability to grow our distribution and transmission businesses is subject to numerous risks and events, many of which are outside of our control.

Our ability to capitalize on investment opportunities available to our transmission business depends, in part, on successful recovery of our transmission investments. Factors that may affect rate recovery of our transmission investments include: (1) FERC’s timely approval of rates to recover such investments; (2) whether the investments are included in PJM's Regional Transmission Expansion Plan; (3) FERC's evolving policies with respect to incentive rates for transmission assets; (4) FERC's evolving policies with respect to the calculation of the base ROE component of transmission rates; (5) consideration and potential impact of the objections of those who oppose such investments and their recovery; and (6) timely development, construction, and operation of the new facilities.

Our ability to capitalize on investment opportunities available to our distribution business depends, in part, on any future distribution rate cases or other filings seeking cost recovery for distribution system enhancements in the states where our Utilities operate and transmission rate filings at FERC, including maintaining the affordability of the rates charged to customers. Any denial of, or delay in, the approval of any future distribution or transmission rate requests could restrict us from fully recovering our cost of service, may impose risks on the distribution and transmission operations, and could have a material adverse effect on our regulatory strategy, results of operations and financial condition.

Our efforts also could be adversely impacted by any impediments to our ability to finance the proposed expansion projects while maintaining adequate liquidity. There can be no assurance that our investment strategy in our distribution and transmission businesses will deliver the desired result, which could adversely affect our results of operations and financial condition.

Complex and changing government regulations and actions, including those associated with rates, could have a negative impact on our business, financial condition, results of operations and cash flows.

We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, have in the past and could in the future require us to incur additional costs, which could be substantial, or change the way we conduct our business, and therefore could have a material adverse impact on our results of operations and financial condition.

Particularly, our Utilities and Transmission Companies provide service at rates approved by one or more regulatory commissions. Thus, the rates the Utilities and Transmission Companies are allowed to charge may be decreased as a result of actions taken by FERC or by a state regulatory commission in the states in which our Utilities operate. Also, these rates may not be set to recover such applicable utility's expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered, if at all. While rate regulation is premised on providing an opportunity to earn a reasonable return on investments and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.

State rate regulation may delay or deny full recovery of costs and impose risks on our operations. Any denial of or delay in cost recovery could have an adverse effect on our business, results of operations, liquidity, cash flows and financial condition.

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Each of the Utilities' retail rates are set by its respective regulatory agency for utilities in the state 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 – through traditional, cost-based regulated utility ratemaking. As a result, any of the Utilities may not be permitted to recover its costs and, even if it is able to do so, there may be a significant delay between the time it incurs such costs and the time it is allowed to recover them. Factors that may affect outcomes in the distribution rate cases include, but are not limited to: (i) the value of plant in service; (ii) authorized rate of return; (iii) capital structure (including hypothetical capital structures); (iv) depreciation rates; (v) the allocation of shared costs, including consolidated deferred income taxes and income taxes payable across the Utilities; (vi) regulatory approval of rate recovery mechanisms for capital investment spending programs; and (vii) the accuracy of forecasts used for ratemaking purposes in "future test year" cases.

FirstEnergy can provide no assurance that any base rate request filed by any of the Utilities will be granted in whole or in part. Any denial of, or delay in, any base rate request could restrict the applicable utility from fully recovering its costs of service, may impose risks on its operations, and may negatively impact such Utility’s results of operations, cash flows and financial condition. In addition, to the extent that any of the Utilities seeks an increase in rates, pressure may be exerted on the applicable legislators and regulators to take steps to control rate increases, including through some form of rate increase moderation, reduction or freeze. Any related public discourse and debate, including with respect to the HB 6 investigation or litigation, can increase uncertainty associated with the regulatory process, the level of rates and revenues that are ultimately obtained, and the ability of the Utility to recover costs. Such uncertainty may restrict operational flexibility and resources, reduce liquidity and increase financing costs.

Federal rate regulation may delay or deny full recovery of costs and impose risks on our operations. Any denial or reduction of, or delay in cost recovery could have an adverse effect on our business, results of operations, cash flows and financial condition.

FERC policy currently permits recovery of prudently incurred costs associated with cost-of-service-based wholesale power rates and the expansion and updating of transmission infrastructure within its jurisdiction. FERC’s policies on recovery of transmission costs continue to evolve, evidenced by ongoing proceedings to determine an appropriate ROE methodology to determine transmission ROEs, and to determine whether FERC’s existing policies on transmission rate incentives should be revised. If FERC were to adopt a different policy regarding recovery of transmission costs or if there is any resulting delay in cost recovery, our strategy of investing in transmission could be adversely affected. If FERC were to lower the rate of return it has authorized for FirstEnergy's cost-based wholesale power rates or transmission investments and facilities, it could reduce future earnings and cash flows, and adversely impact our financial condition.

We could be subject to higher costs and/or penalties related to mandatory reliability standards set by NERC/FERC or changes in the rules of organized markets, which could have an adverse effect on our financial condition.

Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased investments. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1.5 million per day for failure to comply with these mandatory electric reliability standards.

In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.

We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.

As a member of PJM, which is an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in PJM’s market and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by its members.

Risks Related to our Business Operations

The hazardous activities associated with generation and distribution of electricity could adversely impact our results of operations and financial condition.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or actions
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of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.

The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties.

Our business is affected by variations in weather and severe weather conditions.

Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when seasonal weather conditions are milder. For example, in 2023, residential and commercial distribution deliveries were impacted by lower customer usage as a result of the weather. Heating degree days in 2023 were 14% below 2022 and 15% below normal. Cooling degree days in 2023 were 23% below 2022 and 15% below normal.

In addition, severe weather, such as tornadoes, hurricanes, ice or snowstorms, droughts, high winds or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period and could have an adverse effect on our financial condition and results of operations, which adverse effects could be further exacerbated by an increased frequency of such severe weather events.

Cyber-attacks, electronic or physical data security breaches and other disruptions to our information technology systems, or those of third parties we are connected to or do business with, could compromise our business operations, critical and proprietary information and employee and customer data, which could have a material adverse effect on our business, results of operations, financial condition and reputation.

In the ordinary course of our business, we depend on information technology systems that utilize sophisticated operational systems and network infrastructure to run all facets of our regulated generation, transmission and distribution services. Additionally, we store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks. We may also need to provide sensitive data to vendors and service providers who require access to this information. The secure maintenance of information and information technology systems is critical to our operations.

Over the last several years, there has been an increase in the frequency of cyber-attacks by terrorists, hackers, international activist organizations, foreign governments and individuals. These and other unauthorized parties may attempt to gain access to our network systems or facilities, or those of third parties with whom we do business in many ways, including directly through our network infrastructure or through fraud, trickery, or other forms of deception against our employees, contractors and temporary staff. Additionally, our information and information technology systems and those of our vendors and service providers may be increasingly vulnerable to data security breaches, damage and/or interruption due to viruses, ransomware, unauthorized physical access, theft of access devices, human error, malfeasance, faulty password management or other malfunctions and disruptions. Further, hardware, software, or applications we develop or procure from third parties may contain defects in design or manufacture or other problems that could unexpectedly compromise information and/or security.

As a source of critical infrastructure, the energy industry is at heightened threat of cyber-attacks, which are becoming increasingly more difficult to anticipate and prevent due to their rapidly evolving nature. We cannot anticipate, detect, or implement fully preventive measures against all cyber security threats because the techniques used are increasingly sophisticated and constantly evolving. For example, as artificial intelligence continues to evolve, cyber-attackers could use artificial intelligence to develop malicious code, denial-of-service attacks, sophisticated phishing attempts and other attacks leading to data loss, loss of operational control, or exploitation of inherent vulnerabilities.

In addition, the increased use of smartphones, tablets, and other wireless devices, as well as ongoing remote work-from-home arrangements for a substantial portion of our corporate employees, may also heighten these and other operational risks. Furthermore, economic sanctions issued by one country against another, such as those issued by the U.S. and other countries against Russia in response to its war with Ukraine, or other increasing global geopolitical tensions, such as the war between Israel and Hamas, could increase the risk of state-sponsored cyber-attacks.

Despite security measures and safeguards we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure, as well as the transmission facilities of third parties with whom we are interconnected, may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat security measures and gain access to our information technology systems may be made. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be
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adversely affected by cyber-attacks or other unexpected or uncontrollable events occurring on the systems of such third parties. Given the rapidly evolving nature, sophistication, and complexity of cyber-attacks, despite our reasonable efforts to mitigate and prevent such attacks, it is possible that we may not be able to anticipate, prevent, detect, or implement effective preventive measures to protect against all cyber-attack incidents.

Any actual or perceived cyber-attack, data security breach, damage, interruption and/or defect could: (i) disable our generation, transmission (including our interconnected regional transmission grid) and/or distribution services for a significant period of time; (ii) delay development and construction of new facilities or capital improvement projects; (iii) adversely affect our customer operations; (iv) expose us to increased risk of lawsuits; (v) expose us to increased risk of regulatory penalties; (vi) expose us to increased risk of loss of potential or existing customers; (vii) expose us to increased risk of damage relating to loss of proprietary information; (viii) corrupt data; and/or (ix) result in unauthorized access to the information stored in our data centers and on our networks and those of our vendors and service providers, including, company proprietary information, supplier information, employee data, and personal customer data, causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in economic loss and liability and harmful effects on the environment and human health, including loss of life. Additionally, because our regulated generation, transmission and distribution services are part of an interconnected system, disruption caused by a cyber security incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our operations.

Although we maintain cyber insurance and property and casualty insurance, there can be no assurance that liabilities or losses we may incur, including as a result of cyber security-related litigation, will be covered under such policies or that the amount of insurance will be adequate. Further, as cyber threats continually evolve and become more difficult to detect and successfully defend against, there can be no assurance that we can implement or maintain adequate preventive measures, accurately assess the likelihood of a cyber-incident or quantify potential liabilities or losses. Also, we may not discover any data security breach and loss of information for a significant period of time after the data security breach occurs particularly those of our vendors and service providers.

For all of these reasons, any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the loss of confidential, sensitive, and proprietary information, including but not limited to personal information of our customers, employees, suppliers, vendors and other third parties, the use of significant management resources, legal claims or proceedings, regulatory penalties, significant remediation costs, increased regulation, increased capital costs, increased insurance costs, increased protection costs for enhanced cyber security systems or personnel, damage to our reputation and/or the rendering of our internal controls ineffective, all of which could materially adversely affect our business, results of operations, financial condition and reputation.

If our cost saving initiatives do not achieve the expected benefits, there could be negative impacts to FirstEnergy's business, results of operations and financial condition.

FirstEnergy is engaged in an ongoing effort to create a culture of continuous improvement to strategically reduce our operating expenditures and continually reinvest in a more diverse capital program in support of our long-term strategy. FirstEnergy leverages opportunities to reduce costs – such as filling only critical positions, implementing our facility optimization plans, as well as exploring other additional, sustainable opportunities, such as reducing contractor spend. There can be no assurance that implementation of our continuous improvement culture will allow us to realize the anticipated benefits to our business, results of operations and financial condition in a timely manner, if at all.

Our ability to achieve the continued benefits from our cost saving initiatives is subject to many estimates and assumptions as well as our ability to hire recruit and retain an appropriately qualified workforce and implement a culture of continuous improvement. FirstEnergy could experience unexpected delays and business disruptions resulting from supporting these initiatives, decreased productivity, and higher than anticipated costs, any of which may impair our ability to reduce operating expenditures and to achieve anticipated results or otherwise harm FirstEnergy's business, results of operations and financial condition.

Inflation and interest rate pressures may negatively impact our financial condition, results of operations, liquidity, and cash flows.

Prices for equipment, materials, supplies, employee labor contractor services, together with the cost of variable-rate debt have increased during 2023, and could continue to increase in 2024 and beyond. Long-term inflationary pressures may result in such prices continuing to increase more quickly than expected. Inflation increases costs for labor, materials and services, and we may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely impact our financial condition, results of operations, liquidity, and cash flows.

Continued supply chain disruptions could have an adverse effect on our results of operations, cash flow and financial condition.

We have continued to experience supply chain challenges due to economic conditions that developed during the COVID-19 pandemic, with order lead times increasing across numerous material categories and with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with increasing inflationary pressure, have increased the costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material
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impact on its capital spending plan. However, the situation is subject to change 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.

We are subject to financial performance risks from regional and general economic cycles as well as data centers and heavy industries such as shale gas, automotive, chemical and steel.

Our business follows economic cycles. Economic conditions, including inflationary and interest rate pressures, impact the demand for electricity and therefore declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in industries in our business territories, e.g., data centers, shale gas, automotive, chemical, steel and other heavy industries, and as these conditions and resultant demand of those industries for electricity generation changes, our revenues will be impacted.

We are subject to risks arising from the operation of our power plants and transmission and distribution equipment which could reduce revenues, increase expenses and have a material adverse effect on our business, financial condition and results of operations.

Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, human error in operations or maintenance, acts of terrorism or sabotage, cyber-attacks, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and operational performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Capital investments and construction projects may not be completed within forecasted budget, schedule or scope parameters or could be canceled which could adversely affect our business and results of operations.

Our Energize365 business plan calls for extensive capital investments totaling approximately $26 billion from 2024 through 2028, including but not limited to our transmission expansion program and our distribution grid modernization, resiliency and reliability programs. We may be exposed to the risk of substantial price increases in, or the adequacy or availability of, the costs of labor and materials used in construction, nonperformance of equipment and increased costs due to inflation, delays, including delays relating to the procurement of permits or approvals, adverse weather or environmental matters. We engage numerous contractors and enter into a large number of construction agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. Also, because we enter into construction agreements for the necessary materials and to obtain the required construction related services, any cancellation by FirstEnergy of a construction agreement could result in significant termination payments or penalties. Any delays, increased costs or losses, or cancellation of a construction project could adversely affect our business and results of operations, particularly if we are not permitted to recover any such costs in rates.

Physical acts of war, terrorism, sabotage or other attacks on any of our facilities or other infrastructure could have an adverse effect on our business, results of operations, cash flows and financial condition.

As a result of the continued threat of physical acts of war, terrorism, sabotage or other attacks in the United States, our electric generation, fuel storage, transmission and distribution facilities and other infrastructure, including power plants, transformer and high voltage lines and substations, or the facilities or other infrastructure of an interconnected company, could be direct targets of, or indirect casualties of, an act of war, terrorism, sabotage or other attack, which could result in disruption of our ability to generate, purchase, transmit or distribute electricity for a significant period of time, otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such disruption or incident could result in a significant decrease in revenue, significant additional capital and operating costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our assets over and above any available insurance reimbursement, higher insurance deductibles, higher premiums and more restrictive insurance policies, legal claims or proceedings, greater regulation with higher attendant costs, generally, and significant damage to our reputation, which could have a material adverse effect on our business, results of operations, cash flows and financial condition.

Failure to provide safe and reliable service and equipment could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results.

We are committed to providing safe and reliable service and equipment in our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. However, our employees, contractors and the general public may be exposed to dangerous environments due to the nature of our operations. Failure to provide safe and reliable
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service and equipment due to various factors, including cyber or physical attacks, equipment failure, accidents weather or natural disasters, could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results through reduced revenues, increased capital and operating costs, litigation or the imposition of penalties/fines or other adverse regulatory outcomes.

The outcome of litigation, arbitration, mediation, and similar proceedings involving our business, or that of one or more of our operating subsidiaries, is unpredictable. An adverse decision in any material proceeding could have a material adverse effect on our financial condition and results of operations.

We are involved in a number of litigation, arbitration, mediation, and similar proceedings, including with respect to asbestos claims. These and other matters may divert financial and management resources that would otherwise be used to benefit our operations. Further, no assurances can be given that the resolution of these matters will be favorable to us. If certain matters were ultimately resolved unfavorably to us, the results of operations and financial condition of FirstEnergy could be materially adversely impacted.

In addition, we are sometimes subject to investigations and inquiries by various state and federal regulators due to the heavily regulated nature of our industry. Any material inquiry or investigation could potentially result in an adverse ruling against us, which could have a material adverse impact on our financial condition and operating results.

We face certain human resource risks associated with potential labor disruptions and/or with the availability of trained and qualified labor to meet our future staffing requirements.

We are continually challenged to find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. On May 9, 2023, FirstEnergy announced a voluntary retirement program for eligible non-bargaining employees, known as the PEER. More than 65% of eligible employees, totaling approximately 450 employees, accepted the PEER, which included lump sum compensation equivalent to severance benefits, healthcare continuation costs and a temporary pension enhancement. Most PEER participating employees departed in 2023. Our costs, including costs for contractors to replace employees and productivity costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully recruit and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Additionally, a significant number of our physical workforce are represented by unions. While we believe that our relations with our employees are generally fair, we cannot provide assurances that the company will be completely free of labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, lockouts or that any labor disruption will be favorably resolved. Mitigating these risks could require additional financial commitments and the failure to prevent labor disruptions and retain and/or attract trained and qualified labor could have an adverse effect on our business.

Significant increases in our operation and maintenance expenses, including our health care and pension costs, could adversely affect our future earnings and liquidity.

We continually focus on limiting and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures related to operation and maintenance expenses, including in the areas of health care and pension costs. We have experienced health care cost inflation in recent years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, discount rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Pension and OPEB Accounting.” While we anticipate that our operation and maintenance expenses will continue to increase, if actual results differ materially from our assumptions, our costs could be significantly higher than expected which could adversely affect our results of operations, financial condition and liquidity.

Advances and widespread adoption in distributed generation and regulatory policies may make our facilities significantly less competitive and adversely affect our results of operations.

Traditionally, electricity is generated at large, central station generation facilities distributed by our systems. This method results in economies of scale and lower unit costs than newer generation technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in newer generation technologies will make newer generation technologies more cost-effective, or that legislation addressing climate change at the federal or state level together with changes in regulatory policy will create incentives or benefits that otherwise make these newer generation technologies even more competitive with central station electricity production. To the extent that newer generation technologies are connected directly to load, bypassing the transmission and distribution systems, potential impacts could include decreased transmission and distribution revenues,
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stranded assets and increased uncertainty in load forecasting and integrated resource planning and could adversely affect our business and results of operations.

Energy companies are subject to adverse publicity causing less favorable regulatory and legislative outcomes which could have an adverse impact on our business.

Energy companies, including the Utilities and Transmission Companies, have been the subject of criticism on matters including the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, as well as negative publicity associated with the operation of coal-fired generation or proceedings seeking regulatory recoveries may cause less favorable legislative and regulatory outcomes and damage our reputation, which could have an adverse impact on our business.

Our results of operations could be adversely affected by events beyond our control, such as natural disasters, public health crises, political crises, negative global climate patterns, mine subsidence, or other catastrophic events.

Our operations, or those of our vendors or suppliers, could be negatively impacted by various events beyond our control, including, but not limited to: natural disasters, such as hurricanes, tornadoes, floods, earthquakes, extreme cold weather events and other adverse weather conditions; public health crises, such as pandemics and epidemics; political crises, such as terrorist attacks, war, labor unrest, and other political instability (including, without limitation, the ongoing conflict between Russia and Ukraine and the war between Israel and Hamas); negative global climate patterns, especially in water stressed regions; surface subsidence from underground mining impacting our facilities; or other catastrophic events, such as fires or other disasters occurring at our distribution facilities or our service providers’ facilities, whether occurring in the United States or internationally. These events could disrupt the operations of our corporate offices and our supply chain and those of our vendors and service providers, as well as disrupting our infrastructure and that of third parties with whom we are connected. To the extent any of these events occur, our operations and financial results could be adversely affected.

Risks Associated with Climate Change, GHG Emissions and Other Environmental Matters

Our aspirations and disclosures related to EESG matters expose us to risks that could adversely affect our reputation and performance.

We have published statements concerning our EESG goals and aspirations and, in February 2024, we published a Climate Position and Strategy that included an update on our previously-announced GHG emission goals. We are targeting Scope 1 carbon neutrality by 2050, which for us includes emission from coal generation, SF6 leaks from transmission and distribution equipment, and our mobile fleet (i.e., vehicles). These statements reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. Our failure to adequately update, accomplish or accurately track and report on these goals on a timely basis, or at all, could adversely affect our reputation, financial performance and growth, and expose us to increased scrutiny from the investment community, special interest groups and enforcement authorities. Conversely, certain “anti-environmental, social and governance” sentiment among some individuals and government institutions pose the risk that we may face increasing scrutiny, reputational risk, or lawsuits from these parties regarding our EESG initiatives.

Our ability to achieve any EESG objective is subject to our ability to make operational changes and is conditioned upon numerous risks, many of which are outside of our control. Examples of such risks include the evolving regulatory requirements in the jurisdictions in which we operate, the prevalence of certain EESG standards or disclosures, the evolving laws applicable to environmental, social and governance matters, and the availability of funds to invest in EESG initiatives in times where we are seeking to reduce costs.

Standards for tracking and reporting EESG matters continue to evolve. Our selection of voluntary disclosure frameworks and standards, and the interpretation or application of those frameworks and standards, may change from time to time or differ from those of others. Methodologies for reporting EESG data may be updated and previously reported EESG data may be adjusted to reflect improvement in availability and quality of third-party data, changing assumptions, changes in the nature and scope of our operations and other changes in circumstances. Our processes and controls for reporting EESG matters across our operations and supply chain are evolving along with multiple disparate standards for identifying, measuring, and reporting EESG metrics, including EESG-related disclosures that may be required by the SEC, European and other regulators, and such standards may change over time, which could result in significant revisions to our current goals, reported progress in achieving such goals, or ability to achieve such goals in the future. If our EESG practices do not meet evolving investor or other stakeholder expectations and standards, then our reputation or our attractiveness as an investment, business partner, acquiror, service provider or employer could be negatively impacted.

We have coal-fired generation capacity, which exposes us to risk from regulations relating to coal, GHGs and CCRs, which could lead to increased costs or the need to spend significant resources to defend allegations of violation.

We own and maintain coal-fired generating plants located in West Virginia. Historically, coal-fired generation has greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to air emissions, including GHGs and CCR disposal, than other types of electric generation facilities. To the extent that changes in government policies limit or restrict the usage of coal as a source of fuel in generating electricity or alternate fuels, such as
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natural gas, or displace coal on a competitive basis, our business and results of operations could be adversely affected. These legal requirements and any future initiatives could impose substantial additional costs and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities and could require our coal-fired generation to curtail generation or cease to generate. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.

Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses.

Federal and various regional and state authorities regulate GHG emissions, including CO2 emissions and have created financial incentives to reduce them. In 2022, FirstEnergy operated businesses that had total CO2 emissions of approximately 16.5 million metric tons. For existing power generation plants, CO2 emissions data are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. This estimate is based on a number of projections and assumptions that may prove to be incorrect, such as the forecasted dispatch, anticipated plant efficiency, fuel type, CO2 emissions rates and our subsidiaries’ achieving completion of such construction and development projects. While actual emissions may vary substantially, the projects under construction or development when completed will increase emissions of our portfolio and therefore could increase the risks associated with regulation of GHG emissions.

In 2010, the EPA adopted regulations pertaining to GHG emissions that require new and existing sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or modification. In 2016, the U.S. Supreme Court ruled that such permitting would only be required if such sources also must obtain a new source review permit for increases in other regulated pollutants. For further discussion of the regulation of GHG emissions, see Item 1.—Business—Environmental Matters – Climate Change, above. The Parties to the United Nations Framework Convention on Climate Change’s Paris Agreement established a long-term goal of keeping the increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to decarbonize the global economy and to further limit GHG emissions.

Furthermore, the SEC has proposed climate-related disclosure rules that have not yet been enacted as of the date of this report, and certain states have begun to pass their own laws related to GHG emissions. The impact of GHG regulation on our operations will depend on a number of factors, including the degree and timing of GHG emissions reductions required under any such legislation or regulation, the cost of emissions reduction equipment and the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred through rate increases or otherwise. The costs of compliance could be substantial.

We have a minority ownership stake in a coal mine that requires governmental permits and approvals to operate, and a failure of the coal mine to renew and maintain such permits and approvals may adversely affect our results of operations and cash flow.

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 predominantly in international markets. The viability of our investment depends upon several factors beyond our control, including, but not limited to: Signal Peak’s ability to renew and maintain governmental permits and approvals and remain in compliance with federal, state, and local safety and environmental statutes, rules, and regulations affecting the coal mining industry. Failure by Signal Peak to renew and maintain necessary permits and approvals, and to comply with any such statutes, rules and regulations, may impair its operations and the ability to generate cash flows necessary for Global Holding to pay future dividends and contribute to FirstEnergy’s earnings.

Signal Peak operates a single underground coal mine in south-central Montana and must obtain numerous governmental permits and approvals that impose strict conditions and obligations relating to, among other things, various environmental and safety matters in connection with its mining and coal transportation operations. The rules applicable to these permits and approvals are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. In addition, the public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Limitations on Signal Peak’s ability to conduct its mining operations due to its inability to obtain or renew necessary permits or similar approvals could materially reduce or even halt production at the mine resulting in an adverse effect on our balance sheet, results of operations and cash flow.

Signal Peak is currently a party to litigation that is challenging the validity of its permit to expand its mine into adjacent leased federal coal reserves. After receiving initial approval in 2015 from the OSMRE to expand the mine, environmental non-governmental organizations filed suit in the United States District Court for the District of Montana the same year challenging OSMRE’s environmental assessment, which was a finding of no significant impact, and the expansion approval. The District Court affirmed OSMRE’s conclusions. In April 2022, the Ninth Circuit Court reversed the District Court’s ruling affirming the expansion approval and remanded the case back to the District Court. On February 10, 2023, the District Court vacated the permit issued by OSMRE, which restricts Signal Peak’s ability to mine federal coal until OSMRE completes an environmental impact statement and reissues the permit. While the District Court’s ruling is not expected to materially impede Signal Peak’s
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ability to conduct its mining operations over the next 12-24 months, the inability to successfully obtain the permit from OSMRE would prohibit Signal Peak from mining those adjacent leased federal coal reserves and could further adversely impact Signal Peak from efficiently and economically conducting its mining operations thus reducing its production, cash flow and profitability.

Costs of compliance with environmental laws are significant, and the cost of compliance with new environmental laws, including limitations on GHG emissions related to climate change, could adversely affect our cash flows and financial condition.

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for, among other things, installation and operation of pollution control equipment, emissions monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. We may be forced to shut down other facilities or change their operating status, either temporarily or permanently, if we are unable to comply with these or other existing or new environmental requirements, or if the expenditures required to comply with such requirements are unreasonable.

Moreover, new environmental laws or regulations including, but not limited to GHG emissions, Clean Water Act effluent limitations imposing more stringent water discharge regulations, or other changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures or other capital-like investments. Our compliance strategy, including but not limited to, our assumptions regarding estimated compliance costs, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations. Due to the uncertainty of control technologies available to reduce GHG emissions, any legal obligation that requires substantial reductions of GHG emissions could result in substantial additional costs, adversely affecting cash flows and profitability, and raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

The EPA may conduct NSR investigations at our generating plants, which could result in the imposition of fines.

We may be subject to risks from changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of the EPA's NSR programs. Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing generation facilities to the far more stringent new source standards applicable to new generation facilities.

The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards during work considered by the companies to be routine maintenance. The EPA has previously investigated alleged violations of the NSR standards at certain of our existing and former generating facilities. Should the EPA investigate our generating plants in the future, it could, if violations were discovered, result in the imposition of fines.

We are or may be subject to environmental liabilities, including costs of remediation of environmental contamination at current or formerly owned facilities, which could have a material adverse effect on our results of operations and financial condition.

We may be subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned or operated by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We are currently involved in a number of proceedings relating to sites where hazardous substances have been released and we may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former MGP operations are one source of such costs. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material. In addition, there can be no assurance that any liabilities, losses or expenditures we may incur related to such environmental liabilities or contamination will be covered under any applicable insurance policies or that the amount of insurance will be adequate.

In some cases, a third party who has acquired assets including operating and deactivated nuclear power stations from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.

We could be exposed to private rights of action relating to environmental matters seeking damages under various state and federal law theories which could have an adverse impact on our results of operations, financial condition, cash flows and business operations.

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Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other relief. For example, claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in other actions making similar allegations. An unfavorable ruling in any such case could result in the need to make modifications to our coal-fired generation or reduce emissions, suspend operations or pay money damages or penalties. Adverse rulings in these or other types of actions could have an adverse impact on our results of operations, cash flows and financial condition and could significantly impact our business operations.

Transition risks associated with climate change, including those related to regulatory mandates could negatively impact our financial results.

Where federal or state legislation mandates the use of renewable fuel sources, such as wind and solar and such legislation does not also provide for adequate cost recovery of our revenue requirements, it could result in significant changes in our business, including material increases in renewable energy credit purchase costs, purchased power costs and capital investments, as such costs are spread over reduced sales volumes. Such mandatory renewable portfolio requirements may have an adverse effect on our financial condition and results of operations.

A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce peak demand and energy consumption. Such conservation programs have previously resulted in and could result in further load reduction and adversely impact our financial results in different ways. We currently have energy efficiency riders in place in certain of our states to recover the cost of these programs either at or near a current recovery time frame in the states where we operate.

In our regulated operations, energy conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. In the past, we have been adversely impacted by reduced electric usage due in part to energy conservation efforts such as the use of efficient lighting products such as compact fluorescent lights, halogens and light emitting diodes. We are unable to determine what impact, if any, future conservation activities will have on our financial condition or results of operations.

Additionally, failure to meet regulatory or legislative requirements to reduce energy consumption or otherwise increase energy efficiency could result in penalties that could adversely affect our financial results.

Financial and reputational risks associated with owning coal-fired generation and a minority-interest in a coal mine may have an adverse impact on our business operations, financial condition and cash flows.

MP's fleet consists of 3,093 MWs of coal-fired generation and FEV 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 international coal sales. Certain members of the investment community have adopted investment policies promoting the divestment of, or otherwise limiting new investments in, coal-fired generation and coal mining. The impact of such efforts may adversely affect the demand for and price of our common stock and impact our and MP's access to the capital and financial markets. Further, certain insurance companies have established policies limiting coal-related underwriting and investment. Consequently, these policies aimed at coal-fired generation could have a material adverse impact on our reputation, business operations, financial condition, and cash flows.

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 more frequent or more extreme weather events, changes in temperature and precipitation patterns, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. 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.

Risks Associated with Markets and Financial Matters

Our results of operations and financial condition may be adversely affected by the volatility in pension and OPEB investments and obligations due to capital market performance and other changes.

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FirstEnergy recognizes in income the change in the fair value of plan assets and net actuarial gains and losses for its pension and OPEB plans. This adjustment is recognized in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, resulting in greater volatility in pension and OPEB expenses and therefore may materially impact our results of operations.

Our financial statements reflect the values of the assets held in trust to satisfy our obligations under pension and OPEB plans. Certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to pay future pension and other obligations requires significant judgment and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or that negatively impact the discount rate and increase the present value of liabilities may increase our future pension and OPEB expenses and further may have significant impacts on the value of the pension and other trust funds, which could require significant additional funding and negatively impact our results of operations and financial position. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates——Pension and OPEB Accounting.”

Our results of operations and financial condition may be adversely affected by certain risks related to our minority interest in a coal mine.

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 predominantly in international markets. In the second quarter of 2022, FEV received its first dividend of $20 million after more than ten years of equity ownership in the joint venture and received total dividends in 2022 and 2023 of $170 million and $165 million, respectively. Additionally, during 2022 and 2023, FirstEnergy recognized approximately $168 million and $175 million of pre-tax earnings, respectively, from its investment in Global Holding. Global Holding’s ability to positively affect our results of operations or pay future dividends depends upon several factors beyond our control, including, but not limited to: the market price of coal, the availability and reliability of transportation facilities and other systems, geopolitical stability in international markets, and Global Holding’s ability to renew and maintain governmental permits and approvals and remain in compliance with safety and environmental regulations affecting the coal mining industry.

The price for Signal Peak’s coal depends upon factors beyond our control, including: overall global economic and geopolitical conditions, the effect of worldwide energy consumption, including the impact of technological advances on energy consumption; international developments impacting the supply of coal; international developments impacting the supply of oil & gas; and the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations. Any adverse change in these factors could result in weaker demand and lower prices for Global Holding’s products, and, as a result, could impact Global Holding’s ability to pay future dividends, which in turn could adversely affect our cash flow and results of operations.

Failure to comply with debt covenants in our credit agreements or conditions could adversely affect our ability to execute future borrowings and/or require early repayment, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all.

Our debt and credit agreements contain various financial and other covenants including a requirement for FE 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, and that each other borrower maintain a consolidated debt to total capitalization ratio of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

Our credit agreements contain certain negative and affirmative covenants. Our ability to comply with the covenants and restrictions contained in the 2021 Credit Facilities and 2023 Credit Facilities has been and may, in the future, be affected by events related to the ongoing government investigations or otherwise, including a failure to comply with the terms of the DPA.

A breach of any of the covenants contained in our credit agreements, including any breach related to alleged failures to comply with anti-corruption and anti-bribery laws, could result in an event of default under such agreements, and we would not be able to access our credit facilities for additional borrowings and letters of credit while any default exists. Upon the occurrence of such an event of default, any amounts outstanding under our credit facilities could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our credit facilities is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. In addition, certain events, including but not limited to any covenant breach related to alleged failures to comply with anti-corruption and anti-bribery laws, an event of default under our credit agreements, and the acceleration of applicable commitments under such facilities could restrict our ability to obtain additional or replacement financing on acceptable terms or at all. The operating and financial restrictions and covenants in our credit facilities and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities which in turn could have a material adverse impact on our business, cash flow, liquidity and results of operations.

Increasing interest rates and/or a credit rating downgrade could negatively affect our or our subsidiaries’ financing costs, ability to access capital and requirement to post collateral.
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We have near-term exposure to interest rates from outstanding short-term indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise long-term debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets, as well as the U.S. Federal Reserve's interest rate policies, have resulted in volatile interest rates on new publicly issued debt securities and increased costs for variable interest rate debt securities. Disruptions in capital and credit markets, or the Federal Reserve Board's interest rate policies, could result in volatile interest rates on new publicly issued debt securities and increase our financing costs and adversely affect our results of operations, cash flows and liquidity. Also, interest rates could change as a result of economic or other events that are beyond our risk management processes. As a result, we cannot always predict the impact that our risk management decisions may have if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations, cash flows and liquidity.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. Certain of FirstEnergy’s subsidiaries have in the past been subject to downgrade of credit ratings. Any future downgrades in FirstEnergy or FirstEnergy subsidiaries' credit ratings from the nationally recognized credit rating agencies, particularly to levels below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, additional downgrades could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. Additional rating downgrades would further increase our interest expense on certain of FirstEnergy's long-term debt obligations and would also further increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. Such additional rating downgrades could also negatively impact our ability to grow our regulated businesses or execute our business strategies by substantially increasing the cost of, or limiting access to, capital.

In addition, events related to the ongoing government investigations may expose us to higher interest rates for additional indebtedness, whether as a result of ratings downgrades or otherwise, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all. See “Failure to comply with debt covenants in our credit agreements or conditions could adversely affect our ability to execute future borrowings and/or require early repayment, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all.”

In the event of volatility or unfavorable conditions in the capital and credit markets, our business, including the immediate availability and cost of short-term funds for liquidity requirements, our ability to meet long-term commitments and the competitiveness and liquidity of energy markets may be adversely affected, which could negatively impact our results of operations, cash flows and financial condition.

We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use LOCs provided by various financial institutions to support our hedging operations. We also deposit cash in short-term investments. In the event of volatility in the capital and credit markets, our ability to draw on our credit facilities and cash may be adversely affected. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.

Should there be fluctuations in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant foreign or domestic financial institutions or foreign governments, our access to liquidity needed for our business could be adversely affected. Unfavorable conditions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other capital-like investments, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.

The IRA of 2022 could change the rate of taxes imposed on us and could negatively affect our cash flows and financial condition.

On August 16, 2022, President Biden signed into law the IRA of 2022, which, 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 net operating losses 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 it will be subject to the AMT beginning in 2023. Accordingly, FirstEnergy made a first quarter estimated payment of AMT of approximately $49 million in April
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2023. In June 2023, the U.S. Treasury issued additional guidance that eliminated the requirement of corporations to include AMT in quarterly estimated tax payments, pending further guidance on the application and administration of AMT. Therefore, as a result of guidance issued to date, the current forecast of AMT obligation, and the amount of AMT already paid in April 2023, FirstEnergy did not make any additional AMT payments for the 2023 tax year. Until final U.S. Treasury regulations are issued, the amount of AMT FirstEnergy pays could be significantly different than current estimates or it may not be a payer at all. 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.

Changes in local, state or federal tax laws applicable to us or adverse audit results or tax rulings, and any resulting increases in taxes and fees, may adversely affect our results of operations, financial condition and cash flows.

FirstEnergy is subject to various local, state and federal taxes, including income, franchise, real estate, sales and use and employment-related taxes. We exercise significant judgment in calculating such tax obligations, booking reserves as necessary to reflect potential adverse outcomes regarding tax positions we have taken and utilizing tax benefits, such as carryforwards and credits. Additionally, various tax rate and fee increases may be proposed or considered in connection with such changes in local, state or federal tax law. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by legislatures or regulatory bodies. Any such changes, or any adverse tax audit results or adverse tax rulings on positions taken by FirstEnergy or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.

We cannot predict whether, when or to what extent new U.S. tax laws, regulations, interpretations or rulings will be issued. A reform of U.S. tax laws may be enacted in a manner that negatively impacts our cash flow, results of operations, and financial condition.

We are a holding company and rely on cash from our subsidiaries to meet our financial obligations and therefore any restrictions on the utilities and transmission companies’ ability to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.

Because FE is a holding company with no operations or cash flows of its own, our ability to meet our financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on our common stock, is primarily dependent on the net income and cash flows of our subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding FE, our subsidiaries have regulatory restrictions and financial obligations that must be satisfied.

For example, the Utilities and Transmission Companies are regulated by various state utility and federal commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state and federal commissions could attempt to impose restrictions on the ability of the Utilities and Transmission Companies to pay dividends or otherwise restrict cash payments to us. Any inability of our subsidiaries to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.

We may also provide capital contributions or debt financing to our subsidiaries under certain circumstances, which would reduce the funds available to meet financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on our common stock.

We cannot assure common shareholders that future dividend payments will be made, or if made, in what amounts they may be paid.

The FE Board will continue to regularly evaluate our common stock dividend and determine whether to declare a dividend, and an appropriate amount thereof, each quarter taking into account such factors as, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.

ITEM 1B.     UNRESOLVED STAFF COMMENTS

None.

ITEM 1C.     CYBERSECURITY

FirstEnergy seeks to protect its customers, employees, facilities and the ongoing reliability of the electric system. FirstEnergy works closely with state and federal agencies and its peers in the electric utility industry to identify physical and cyber security
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risks, exchange information, and put safeguards in place to comply with strict reliability and security standards. From a security standpoint, the electric utility sector is one of the most regulated industries.
Risk Management and Strategy

FirstEnergy has established a broad framework to assess, identify and manage material risks from cyber security threats. This program is established at the executive level, with regular reporting to, and oversight by, the FE Board as described below. At the highest level, FirstEnergy’s program includes multi-layered governance by management, the Audit Committee, the Operations and Safety Committee, and the FE Board, as described in greater detail below.

Central management and coordination of the program helps FirstEnergy to comprehensively evaluate and protect against cyber threats. FirstEnergy’s policies and procedures identify how cyber security measures and controls are developed, implemented, and regularly reviewed and updated. FirstEnergy aims to align its cyber security program with national standards. For example, FirstEnergy has implemented and maintains a set of controls to manage cyber security risk based on the National Institute of Standards and Technology Cyber Security Framework and, for Bulk Electric System assets, the NERC Critical Infrastructure Protection standards. FirstEnergy also complies with various state laws and regulations on cyber security.

FirstEnergy’s Cyber Security Program identifies security controls and user responsibilities for the organization to identify and manage the risk of a cyber security incident. FirstEnergy also conducts various internal and external risk assessments each year, which are based on nationally accepted standards. These can include annual compliance required assessments, such as requirements under the Sarbanes-Oxley Act and Payment Card Industry compliance audits, as well as ad-hoc assessments driven by emerging risks, changes in FirstEnergy’s environment, or benchmark/roadmap needs. Risks identified in such assessments are considered for inclusion in FirstEnergy’s risk portfolio, or incorporated directly into the Cyber Security Program, and are then prioritized and addressed as needed through the organization’s policies and procedures. The risk assessment along with risk-based analysis and judgment are used to select security controls to address risks. During this process, the following factors, among others, are considered: likelihood and severity of risk, impact on FirstEnergy and others, such as vendors and customers, if a risk materializes, feasibility and cost of controls, and impact of controls on operations and others. FirstEnergy also regularly evaluates the adequacy and sufficiency of specific controls.

To further protect its information and cyber assets, FirstEnergy has required since late 2022 that applicable prospective third-party vendors complete a privacy impact assessment, which is designed to identify potential privacy and cyber security risks for those vendors requiring access to personally identifiable information, and based on the results, include appropriate contractual provisions to mitigate any identified risks. FirstEnergy is also currently evaluating its current third-party vendors to identify which vendors have similar access to personally identifiable information and expects to complete its analysis by the end of 2024.

FirstEnergy conducts cyber security exercises and training. For example, all personnel with any form of computer system access must complete cyber security training on a recurring basis, which educates the personnel on FirstEnergy’s policies and procedures for using FirstEnergy systems, keeping FirstEnergy information secure, and for safe, reliable operation of electric utility systems. FirstEnergy also conducts various tests of its cyber incident response plans, disaster recovery plans and business continuity plans with key stakeholders and responders for various areas of FirstEnergy’s utility and business functions. FirstEnergy’s management also holds executive cyber security incident tabletop exercises to train on cyber security incident response.

Additionally, FirstEnergy leverages third-party security firms in various capacities to assist with various aspects of FirstEnergy’s cyber security program, including risk assessments, vulnerability scans, and penetration testing. FirstEnergy uses a variety of processes to address cyber security threats related to the use of third-party technology and services, such as reviewing independent assessments of the third party’s cyber/information security controls, such as Systems and Organization Controls 2 audits or other standards-based assessments, where appropriate. As part of FirstEnergy’s process to continuously improve its cyber and information security programs, FirstEnergy also engages third-party subject matter experts to assess and evaluate the effectiveness of various aspects of such programs.

In addition to the aforementioned efforts, FirstEnergy also strongly considers cyber security risks as a part of its overall strategy and invests heavily in sophisticated and layered security measures that use both technology and hard defenses to protect critical transmission facilities and its digital communications networks. For example, security enhancements to FirstEnergy’s transmission infrastructure, such as enhanced cyber security monitoring and alarming are a key component of FirstEnergy’s transmission investment program.

Despite the security measures and safeguards FirstEnergy has employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, FirstEnergy’s infrastructure may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat security measures and gain access to information technology systems may be made. Also, FirstEnergy, or its vendors and service providers, may be at an increased risk of a cyber-attack and/or data security breach due to the nature of its business. Any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the use of significant management resources, legal claims or proceedings, regulatory penalties, significant remediation costs, increased regulation, increased capital costs, increased protection costs for enhanced cyber security systems
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or personnel, damage to FirstEnergy's reputation and/or the rendering of its internal controls ineffective, all of which could materially adversely affect FirstEnergy's business, results of operations, financial condition and reputation.

Board Governance and Management

The FE Board has identified cyber security as a key enterprise risk and prioritizes the mitigation of this risk through FirstEnergy’s enterprise risk management process. Responsibility for oversight of risk management generally lies with the FE Board and the Audit Committee has primary responsibility to oversee enterprise risk management. To effectively manage oversight of FirstEnergy’s cyber security risk management practices, since 2022, the FE Board has delegated oversight authority to each of FirstEnergy’s Audit and Operations and Safety Committees, respectively, as detailed in each Committees’ charters. The Audit Committee has primary responsibility to oversee the disclosure of material cyber security incidents, as well as the general obligation to ensure the proper risk oversight structure of cyber security as part of the FirstEnergy’s overall enterprise risk management program and the internal controls applicable to cyber security matters. The Operations and Safety Oversight Committee has primary responsibility to oversee the operational aspects of FirstEnergy’s cyber security policies, programs, initiatives and strategies, as well as operational risk considerations related to cyber security matters. FirstEnergy’s CISO regularly provides reports at the Audit Committee, Operations and Safety Oversight Committee, and the full FE Board. Each such Committee and the full FE Board work collaboratively to ensure fulsome oversight with the proper focus of each respective Board body. These reports include, among other things, current and emerging cyber security risks to FirstEnergy, incidents that were escalated to management during the prior quarter, including those that did not require immediate escalation to the appropriate Committee and/or full FE Board, internal and external assessments of FirstEnergy’s cyber security program, and a roadmap of projects to manage its cyber security posture.

At the executive and management level, the CISO has primary responsibility for the development, operation, and maintenance of FirstEnergy’s cyber security program. The CISO has 5 years of experience in technology risk management, all of which have been with FirstEnergy, and an additional 23 years of experience in information technology. The CISO has passed examinations and received the International Information System Security Certification Consortium Certified Information Systems Security Professional certification. The CISO reports directly to FirstEnergy’s Chief Information Officer. Under the CISO’s oversight, FirstEnergy’s cyber security team implements and provides governance and functional oversight for cyber security controls and services. Cyber security processes include escalation of certain risks and incidents, including those that originate or occur at third parties, to the Chief Information Officer, legal, and the executive leaders as appropriate based on the severity of any such risk or incident. In addition, regular updates from the cyber security teams, in conjunction with real-time escalation on an as-needed basis, are also used to update the risk landscape.

In the event of any significant cyber security incident, FirstEnergy’s Cyber Security Incident Response Plan provides for a severity determination by a cyber security incident response team based on factors such as the number of assets affected, the likelihood of inappropriate data exposure, operational impact, reliability impact, and regulatory impact. Dependent upon the severity of an incident, it is FirstEnergy’s practice to escalate the incident to the Chief Information Officer, Chief Risk Officer, and the FE senior leadership team, including the Chief Legal Officer, Chief Financial Officer, and Chief Executive Officer. Such members of management then determine whether, based on various factors, the incident requires immediate escalation to the Audit and Operations and Safety Committees or full FE Board.

Although the risks from cyber threats have not materially affected FirstEnergy’s business strategy, results of operations, or financial condition to date, FirstEnergy continues to closely monitor cyber risk. Overall, FirstEnergy has implemented tactical processes for assessing, identifying, and managing material risks from cyber security threats to FirstEnergy including governance at the executive and board level of FirstEnergy’s Cyber Security Program, including FE’s risk management strategy and the controls designed to protect its operations. Additionally, FirstEnergy, through its Disclosure Committee, has updated its disclosure controls and procedures to ensure appropriate disclosure of any material cyber security incidents. See Item 1A. Risk Factors for additional information regarding FirstEnergy’s cyber security risks. Those sections of Item 1A. Risk Factors should be read in conjunction with this Item 1C. Cybersecurity.

ITEM 2.     PROPERTIES

The first mortgage indentures for the Ohio Companies, Penn, MP, PE and WP constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. The outstanding debt under the FMBs of specific FE PA predecessors (WP and Penn) were assumed by FE PA in connection with the PA Consolidation. See Note 11, "Capitalization," of the Notes to Consolidated Financial Statements for information concerning financing encumbrances affecting certain of the Utilities’ properties.
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FirstEnergy controls the following generation sources as of December 31, 2023, shown in the table below, and operates in the PJM Region. Except for the OVEC participation referenced in the footnotes to the table, the Regulated Distribution segment generating units are owned by MP.
Plant (Location)UnitTotalCorp / OtherRegulated DistributionTotalCorp / OtherRegulated Distribution
Net Maximum Capacity (MW)
Net(3) Generation for the year ended December 31, 2023
 (Thousand MWh)
Super-critical Coal-fired:  
Harrison (Haywood, WV)1-31,984 — 1,984 11,193 — 11,193 
Fort Martin (Maidsville, WV)1-21,098 — 1,098 4,368 — 4,368 
3,082 — 3,082 15,561 — 15,561 
Sub-critical and Other Coal-fired:
OVEC (Cheshire, OH) (Madison, IN)(1)
1-1178 67 11 335 288 47 
Pumped-storage Hydro:  
Bath County (Warm Springs, VA)(2)
1-6487 — 487 656 — 656 
Total 3,647 67 3,580 16,552 288 16,264 
(1) Represents AE Supply's 3.01% and MP's 0.49% entitlement based on their participation in OVEC.
(2) Represents AGC's 16.25% undivided interest in Bath County. The station is operated by VEPCO.
(3) Each plant is net of station use, except for Bath County, which is shown gross of pumping usage.

MP and PE are constructing 50 MWs of solar generation at five sites in West Virginia. The WVPSC approved the construction of three of the five solar sites. The first solar generation site, located in Maidsville, West Virginia, was completed and placed in-service on January 8, 2024, representing 19 MWs of 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 capacity.

As of December 31, 2023, FirstEnergy’s distribution and transmission circuit miles are located in PJM and were as follows:
Distribution
Line Miles(1)
Transmission
Line Miles
ATSI— 7,950 
CEI33,662 — 
JCP&L24,567 2,596 
MAIT— 4,287 
ME(2)
19,316 — 
MP22,946 2,607 
OE68,357 — 
PE20,096 2,087 
Penn(2)
13,757 — 
PN(2)
28,172 — 
TE19,323 — 
TrAIL— 269 
WP(2)(3)
25,564 4,318 
Total275,760 24,114 
(1) Includes overhead pole line and underground conduit carrying primary, secondary and street lighting circuits.
(2) On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity.
(3) On January 1, 2024, certain of WP's Pennsylvania-based transmission assets were transferred to KATCo

ITEM 3.     LEGAL PROCEEDINGS

Reference is made to Note 13, "Regulatory Matters," and Note 14, "Commitments, Guarantees and Contingencies," of the Notes to Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy.

ITEM 4.     MINE SAFETY DISCLOSURES

Not applicable.

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PART II
ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

COMMON STOCK

The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.

HOLDERS OF COMMON STOCK

There were 57,291 holders of 574,335,396 shares of FE’s common stock as of December 31, 2023, and 57,291 holders of 574,440,850 shares of FE's common stock as of January 31, 2024. FE has historically paid quarterly cash dividends on its common stock. 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, cash flows, credit metrics, risks and uncertainties of the government investigations and other business conditions. Information regarding retained earnings available for payment of cash dividends is given in Note 11, "Capitalization," of the Notes to Consolidated Financial Statements.

SHAREHOLDER RETURN

The following graph shows the total cumulative return from a $100 investment on December 31, 2018, in FE’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
1230
FirstEnergy had no transactions regarding purchases of FE common stock during the fourth quarter of 2023.

FirstEnergy does not have any publicly announced plan or program for share purchases.
ITEM 6.     [RESERVED]
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements: This Form 10-K 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, rising interest rates, inflationary pressure, supply chain disruptions, higher energy costs, and workforce impacts, affecting us and/or our customers and those vendors with which we do business.
•Weather conditions, such as temperature variations and severe weather conditions, or 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, 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 our credit metrics, growing earnings, strengthening our balance sheet, and satisfying the conditions necessary to close the FET Minority Equity Interest Sale.
•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.
•Changes to environmental laws and regulations, including, but not limited to, those 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, 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
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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.

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in (a) Item 1A. Risk Factors, (b) Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in FirstEnergy's other filings with the SEC. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. We expressly disclaim any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference as a result of new information, future events or otherwise.

Forward-looking and other statements in this Annual Report on Form 10-K 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.
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FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRSTENERGY’S BUSINESS

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments Regulated Distribution and Regulated Transmission.

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, making FE PA a new, single operating entity. In addition to merging each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies, (i) WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and (ii) PN and ME contributed their respective Class B equity interests of MAIT to FE. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and serves an area with a population of approximately 4.5 million. FE PA operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.

The Regulated Distribution segment distributes electricity through FirstEnergy’s utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey, and Maryland. This segment also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The service areas and number of customers served by FirstEnergy's regulated distribution utilities as of December 31, 2023, are summarized below:
CompanyArea ServedCustomers Served
(In thousands)
JCP&LNorthern, Western and East Central New Jersey1,167 
OECentral and Northeastern Ohio1,072 
CEINortheastern Ohio758 
WPSouthwest, South Central and Northern Pennsylvania739 
PNWestern, Northern, and South Central Pennsylvania, and Western New York589 
MEEastern Pennsylvania590 
PEWestern Maryland and Eastern West Virginia445 
MPNorthern, Central and Southeastern West Virginia397 
TENorthwestern Ohio316 
PennWestern Pennsylvania171 
6,244 

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are derived from primarily 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.

As described above, Brookfield holds 19.9% of the issued and outstanding membership interests of FET and has entered into an agreement to purchase from FE, an incremental 30% equity interest in FET, such that Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1%. The transaction is subject to customary closing conditions, including PPUC approval, and is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

Corporate/Other reflects corporate support and other costs not charged or attributable to the Utilities 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 elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2023, 67 MWs of electric generating capacity,
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representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2023, Corporate/Other had approximately $7.1 billion of external FE holding company debt.

In 2024, FirstEnergy changed its reportable segments to include the following:
•Distribution Segment, which will consist of the Ohio Companies and FE PA;
•Integrated Segment, which will consist of MP, PE and JCP&L; and
•Stand-Alone Transmission Segment, which will consist of FE's ownership in FET and KATCo.

On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo. Corporate/Other will continue to reflect corporate support and other support costs not charged or attributable to the Utilities 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.
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EXECUTIVE SUMMARY

FirstEnergy is a forward-thinking electric utility centered on integrity, powered by a diverse team of employees, committed to making customers’ lives brighter, the environment better and our communities stronger.

FirstEnergy's core values encompass what matters most to the company. They guide the decisions we make and the actions we take. FirstEnergy's core values should inspire our actions today and shine a light on who we aspire to be in the future.

FirstEnergy Core Values:

•Integrity: We always act ethically with honesty, humility and accountability.

•Safety: We keep ourselves and others safe.

•Diversity, Equity and Inclusion: We embrace differences, ensure every employee is treated fairly and create a culture where everyone feels they belong.

•Performance Excellence: We pursue excellence and seek opportunities for growth, innovation and continuous improvement.

•Stewardship: We positively impact our customers, communities and other stakeholders, and strive to protect the environment.

Employees are encouraged and expected to have conversations with their leaders and peers about the core values and FirstEnergy's commitment to building a culture centered on integrity.

At FirstEnergy, we are dedicated to staying true to our mission and core values. We understand the impact our company can make in the world around us, which means pursuing initiatives and goals that align with our foundational principles, support our EESG and strategic priorities and positively impact our stakeholders.

To solidify our role as an industry leader, we have developed a long-term strategy with priorities that are centered on our mission statement. These priorities reflect a strong foundation with a customer-centered focus that emphasizes modern experiences, new growth and affordable energy bills, and enables the energy transition to a clean, resilient and secure electric grid.

We are proud of the steps we have already taken to demonstrate our commitment to our strategy and look forward to improving our performance and executing on these strategic priorities.

On June 1, 2023, Brian X. Tierney joined the FE Board and began serving as President and Chief Executive Officer of FirstEnergy. Mr. Tierney previously served as Senior Managing Director and Global Head of Operations and Asset Management at Blackstone Infrastructure Partners. Prior to joining Blackstone Infrastructure Partners in July 2021, Mr. Tierney spent 23 years with AEP. John W. Somerhalder II ceased serving as Interim President and Chief Executive Officer on May 31, 2023, and continues to serve as the Chair of the FE Board.

We are focused on making the necessary investments in our core regulated businesses, our employees and in our systems to enhance the customer experience. To execute that vision, we are shifting decision-making and accountability closer to where the work is being done to serve customers. We are making progress to fill several key executive positions in an organization that will be structured to allow greater execution at the business unit level, including the following:

•On November 30, 2023, Toby L. Thomas joined FirstEnergy as the Chief Operating Officer. Mr. Thomas previously served as Senior Vice President, Energy Delivery at AEP, where he was responsible for transmission engineering, construction, operations, maintenance and compliance, and creating efficiencies by bringing together transmission and distribution-related engineering and standards. Mr. Thomas spent 22 years at AEP.

•On December 18, 2023, A. Wade Smith joined FirstEnergy as President, FirstEnergy Utilities. Mr. Smith previously served as the Executive Vice President and Chief Operating Officer of Puget Sound Energy, Inc. Prior to joining Puget Sound Energy, Inc., Mr. Smith held a variety of roles and has more than 30 years of industry experience.

Additionally, five business unit executives will lead our state operations and our stand-alone transmission companies. In our new organization, the business unit executives will have financial responsibility and will be accountable for regulatory direction and outcomes, as well as operational performance.

Beginning in 2024, FirstEnergy changed its reportable segments to align with its updated organizational structure, and will include: Distribution Segment, which will consist of the Ohio Companies and FE PA; Integrated Segment, which will consist of MP, PE and JCP&L and provides distribution, transmission, and for MP, generation, services to their customers; and Stand-Alone Transmission Segment, which will consist of FE's ownership in FET and KATCo. Corporate/Other will continue to reflect

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corporate support and other support costs not charged to the Distribution, Integrated or Transmission segments, 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. This will simplify its segment reporting to provide more transparency and align with its new organizational structure that allows for financial and operational decision-making in how we manage our business. This provides:

•Greater transparency into our business unit performance;
•Alignment with our cash flow, credit metrics, balance sheet and earnings;
•Simplification of our segment reporting so entire entity resides within a segment; and
•Consistency with peers.

In 2023, FirstEnergy made investments of $3.7 billion, which was $300 million above our original plan. As a fully regulated electric utility, FirstEnergy is focused on stable and predictable earnings and cash flow through investments that deliver enhanced customer service and reliability. 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 a carbon neutral future. Through the Energize365 program, FirstEnergy expects approximately $26 billion in system-wide capital investments from 2024 through 2028, which is comprised of 29% Distribution, 39% Integrated and 32% Stand-Alone Transmission and are focused on the following:

•Energy Transition: Distribution and Transmission investments made to support improvements in grid reliability and resiliency and support interconnection of renewable sources.
◦Clean Energy: Including 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 Grid Mod I and II, Pennsylvania's LTIIP, New Jersey's EnergizeNJ, and implementing advanced metering infrastructure
◦Transmission:
▪Operational Flexibility Projects that build capacity and support 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
▪Upgrade system conditions that enhance reliability
•Infrastructure Renewal: Base distribution projects to address aging infrastructure
•Fossil Generation: Projects to maintain operations of fossil 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.

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, including:

•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. An order is expected in the first quarter of 2024 concurrent with approval of MP and PE’s base rate case described below;
•On March 16, 2023, JCP&L filed a base rate case in New Jersey, requesting a $185 million increase in base distribution revenues, which supports investments to strengthen the energy grid, enhance the customer experience and provide assistance to low-income as well as senior citizen customers. JCP&L subsequently updated its base rate case on August 7, 2023, which, among other things, increased its proposed annual net increase in base rate distribution revenues to approximately $192 million. Key proposals to the filing include: a distribution rate base of $3.1 billion, ROE of 10.4%, and a capital structure of debt/equity of 48%/52%. On 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 provides for an $85 million annual base distribution revenues increase for JCP&L, which, if approved by the NJBPU, is expected to be 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 31, 2023, MP and PE filed a base rate case in West Virginia requesting a $207 million increase in revenue, which supports reliability investments, grid resiliency, an enhanced customer experience and provides assistance to low-income customers. Key proposals to the filing include: a distribution rate base of $3.2 billion, ROE of 10.85%, and a capital structure of debt/equity of 51%/49%. On January 23, 2024, MP, PE and various parties filed with a joint settlement agreement with the WVPSC, which recommends a base rate increase of $105 million. Among other things,

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the settlement additionally includes a new low-income customer advocacy program, storm restoration work and service reliability investments. An order is expected by the end of the first quarter of 2024 with new rates to be effective upon the issuance of such order;
•On October 18, 2023, the MDPSC issued an order approving an annual increase in base distribution rates of $28 million, effective October 19, 2023, with respect to the base rate case that PE filed on March 22, 2023. The MDPSC denied PE’s request to establish a pension/OPEB regulatory asset, rejected the continuation of PE’s EDIS, and allowed recovery of most COVID-19 deferred costs. The MDPSC also ordered an independent audit of certain allocations from FESC to PE and denied recovery of approximately $12 million in rate base associated with certain corporate support costs recorded to capital accounts resulting from the FERC Audit. On January 3, 2024, the MDPSC issued an order granting PE’s request for reconsideration and increased PE’s allowed distribution rates by another $0.7 million;
•On November 9, 2023, JCP&L also filed with the NJBPU a petition for approval of the second phase of its EnergizeNJ program that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from the NJBPU of the base rate case stipulation that was filed on February 2, 2024;
•FE PA plans to file a base rate case by April 2024 and request approval for the continuation of its LTIIP program by the end of the third quarter of 2024;
•The Ohio Companies plan to file a base rate case in the second quarter of 2024.

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 majority of the purchase price is expected to be paid in cash upon closing, and the remainder will be payable by the issuance of a promissory note, which is expected to be repaid by the end of 2024. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the PPUC. In addition, pursuant to the FET P&SA II, FirstEnergy made the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, making FE PA a new, single operating entity. In addition to merging each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies, (i) WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and (ii) PN and ME contributed their respective Class B equity interests of MAIT to FE. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and serves an area with a population of approximately 4.5 million. FE PA operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.

FirstEnergy is focused on continuous improvement, including the strategic reduction of operating expenditures and continued reinvestment in a more diverse capital program in support of our long-term strategy. We have begun implementing our facility optimization plans, which focus on both cost savings and alignment with our flexible working arrangements, and will result in our exiting the General Office in Akron, Ohio, and other corporate facilities in Brecksville, Ohio, Greensburg, Pennsylvania and Morristown, New Jersey beginning in 2024. In December 2023, FirstEnergy purchased the General Office building with the intention to sell in the future. It is currently expected that the exit of the General Office and sale will occur in 2025. Our corporate headquarters will remain in Akron, moving to our West Akron Campus, and we continue 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 our combined efforts will help build a stronger, more sustainable company for the near and long term.

On May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, with a fixed interest rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. However, FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date. See “Capital Resources and Liquidity - Convertible Notes" below for more details.

On May 9, 2023, FirstEnergy announced a voluntary retirement program for eligible non-bargaining employees, known as the PEER. More than 65% of eligible employees, totaling approximately 450 employees, accepted the PEER, which included lump sum compensation equivalent to severance benefits, healthcare continuation costs and a temporary pension enhancement. Most PEER participating employees departed in 2023. The temporary pension enhancement and healthcare continuation costs are classified as special termination costs within net periodic benefit costs (credits). In addition to the PEER, FirstEnergy notified and involuntarily separated approximately 90 employees on May 9, 2023. Management expects the cost savings resulting from these initiatives to support FirstEnergy’s growth plans.


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In September 2023, the FE Board declared a $0.02 per share increase to the quarterly common dividend payable December 1, 2023, to $0.41 per share, which represents a 5% increase compared to the quarterly payments of $0.39 per share paid by FE since March 2020. Modest dividend growth enables 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, cash flows, credit metrics, risks and uncertainties of the government investigations and other business conditions.

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 FES and FENOC 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 will continue to evaluate other lift-outs in the future based on market and other conditions.

Climate Strategy

Our commitment to climate is a significant component of our company’s overarching strategy, especially our desire to enable the transition to a clean energy future. Executing our Climate Strategy and advancing the transition to clean energy 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 pledged in 2020 to achieve carbon neutrality by 2050. This GHG goal addresses company-wide emissions within our direct operational control, also known as Scope 1 emissions, across our transmission, distribution and regulated generation operations. At that time, we also set an interim target to reduce our GHG emissions by 30% from the 2019 baseline by 2030. After careful consideration and evaluation, we have made the determination to remove our interim target and remain focused on our 2050 goal.

FirstEnergy’s primary focus is on our transmission and distribution businesses. However, 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, 2022 - and greatly outnumber the emissions from our transmission and distribution operations. As such, achieving the 2030 interim target was dependent on GHG reductions at Fort Martin and Harrison that could be realized only through a meaningful reduction in operation of these two plants prior to 2030.

In 2020, the interim target and corresponding reduction strategy were believed to be within our operational control. However, the following challenges have emerged, impeding our path to achieve the 2030 interim target:
•West Virginia supports coal generation, from political, regulatory, energy and economic perspectives, as illustrated in 2023 by its energy policy initiatives and actions. We believe an intentional reduction in output at the power stations solely to reduce GHG emissions would not be prudent, as it is inconsistent with the state’s energy policy. In light of the significant retirements of baseload generation scheduled through 2030, as reported by PJM, there is uncertainty about what resources will replace that generating capacity, including energy market developments that may make it more economical than originally projected to run our coal plants.

In light of these challenges, we believe it was prudent to remove our 2030 interim target.

We remain committed to achieving carbon neutrality for Scope 1 emissions by 2050. While we can no longer project that we can meaningfully reduce generation-based GHG emissions in West Virginia by 2030, 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. In 2025, FirstEnergy will 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.


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In addition to moving beyond our two West Virginia power stations, key steps in working toward carbon neutrality by 2050 include:
•Reducing sulfur hexafluoride emissions: We're 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’re targeting 30% electrification of our light-duty and aerial truck fleet by 2030 and 100% electrification by 2050. To reach our electrification goal, we’re 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.

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. The criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA, which is expected in July 2024.

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. If the S.D. Ohio’s final settlement approval is affirmed by the U.S. Court of Appeals for the Sixth Circuit, the settlement agreement is expected to fully resolve these shareholder derivative lawsuits.

The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs.

In addition, 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. Subsequently, on April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the review, inquiries and investigations, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation Further, in letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that it was investigating FirstEnergy’s lobbying and governmental affairs activities concerning HB 6. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement obligates FE to pay a civil penalty of $3.86 million, which was paid in January 2023, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. The first compliance monitoring report was submitted in December 2023.

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. 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 former chairman of the PUCO, Samuel Randazzo, 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. No contingency

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has been reflected in FirstEnergy’s consolidated financial statements, as a loss is neither probable, nor is a loss or range of loss reasonably estimable.

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 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 subsequent 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.

The Form 10-K discusses 2023 and 2022 items and year-over-year comparisons between 2023 and 2022. Discussions of 2021 items and year-over-year comparisons between 2022 and 2021 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of FirstEnergy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, filed with the SEC on February 13, 2023.
RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 15, "Segment Information," of the Notes to Consolidated Financial Statements.

Earnings attributable to FE from continuing operations by business segment was as follows:
(In millions, except per share amounts)For the Years Ended December 31,Increase (Decrease)
2023202220212023 vs 20222022 vs 2021
Earnings Attributable to FE from Continuing Operations by Business Segment:  
Regulated Distribution$740 $957 $1,288 $(217)$(331)
Regulated Transmission514 361 408 153 (47)
Corporate/Other(131)(912)(457)781 (455)
Earnings attributable to FE from continuing operations$1,123 $406 $1,239 $717 176.6 %$(833)(67.2)%
EPS Attributable to FE:
Basic - continuing operations$1.96 $0.71 $2.27 $1.25 $(1.56)
Basic - discontinued operations(0.04)— 0.08 (0.04)(0.08)
Basic$1.92 $0.71 $2.35 $1.21 170.4 %$(1.64)(69.8)%
 
Diluted - continuing operations$1.96 $0.71 $2.27 $1.25 $(1.56)
Diluted - discontinued operations(0.04)— 0.08 (0.04)(0.08)
Diluted$1.92 $0.71 $2.35 $1.21 170.4 %$(1.64)(69.8)%

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Summary of Results of Operations — 2023 Compared with 2022

Financial results for FirstEnergy’s business segments for the years ended December 31, 2023 and 2022, were as follows:
2023 Financial ResultsRegulated DistributionRegulated TransmissionCorporate/Other and Reconciling AdjustmentsFirstEnergy Consolidated
 (In millions)
Revenues:   
Electric$10,814 $2,049 $(170)$12,693 
Other224 5 (52)177 
Total Revenues11,038 2,054 (222)12,870 
Operating Expenses:    
Fuel538 — — 538 
Purchased power4,088 — 20 4,108 
Other operating expenses3,364 423 (193)3,594 
Provision for depreciation1,021 367 73 1,461 
Deferral of regulatory assets, net(256)(5)— (261)
General taxes851 266 47 1,164 
Total Operating Expenses9,606 1,051 (53)10,604 
Other Income (Expense):    
Debt redemption costs— — (36)(36)
Equity method investment earnings— — 175 175 
Miscellaneous income, net130 2 32 164 
Pension and OPEB mark-to-market adjustment(78)(36)36 (78)
Interest expense(618)(256)(250)(1,124)
Capitalized financing costs41 54 2 97 
Total Other Expense(525)(236)(41)(802)
Income taxes (benefits)167 179 (79)267 
Income attributable to noncontrolling interest— 74 — 74 
Earnings (Loss) Attributable to FE from Continuing Operations$740 $514 $(131)$1,123 

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2022 Financial ResultsRegulated DistributionRegulated TransmissionCorporate/Other and Reconciling AdjustmentsFirstEnergy Consolidated
 (In millions)
Revenues:   
Electric$10,596 $1,863 $(159)$12,300 
Other205 5 (51)159 
Total Revenues10,801 1,868 (210)12,459 
Operating Expenses:    
Fuel730 — — 730 
Purchased power3,843 — 20 3,863 
Other operating expenses3,404 616 (203)3,817 
Provision for depreciation967 335 73 1,375 
Deferral of regulatory assets, net(362)(3)— (365)
General taxes831 255 43 1,129 
Total Operating Expenses9,413 1,203 (67)10,549 
Other Income (Expense):    
Debt redemption costs— — (171)(171)
Equity method investment earnings— — 168 168 
Miscellaneous income, net361 36 18 415 
Pension and OPEB mark-to-market adjustment(50)(15)137 72 
Interest expense(526)(230)(283)(1,039)
Capitalized financing costs35 48 1 84 
Total Other Expense(180)(161)(130)(471)
Income taxes251 110 639 1,000 
Income attributable to noncontrolling interest— 33 — 33 
Earnings (Losses) Attributable to FirstEnergy Corp. from Continuing Operations$957 $361 $(912)$406 




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Changes Between 2023 and 2022
Financial Results
Increase (Decrease)		Regulated DistributionRegulated TransmissionCorporate/Other and Reconciling AdjustmentsFirstEnergy Consolidated
 (In millions)
Revenues:   
Electric$218 $186 $(11)$393 
Other19 — (1)18 
Total Revenues237 186 (12)411 
Operating Expenses:    
Fuel(192)— — (192)
Purchased power245 — — 245 
Other operating expenses(40)(193)10 (223)
Provision for depreciation54 32 — 86 
Deferral of regulatory assets, net106 (2)— 104 
General taxes20 11 4 35 
Total Operating Expenses193 (152)14 55 
Other Income (Expense):    
Debt redemption costs— — 135 135 
Equity method investment earnings— — 7 7 
Miscellaneous income, net(231)(34)14 (251)
Pension and OPEB mark-to-market adjustment(28)(21)(101)(150)
Interest expense(92)(26)33 (85)
Capitalized financing costs6 6 1 13 
Total Other Expense(345)(75)89 (331)
Income taxes (benefits)(84)69 (718)(733)
Income attributable to noncontrolling interest— 41 — 41 
Earnings (Loss) Attributable to FE from Continuing Operations$(217)$153 $781 $717 


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Regulated Distribution — 2023 Compared with 2022

Regulated Distribution's earnings attributable to FE from continuing operations decreased $217 million in 2023, as compared to 2022, primarily resulting from lower customer usage as a result of the weather, lower net pension and OPEB credits, and higher interest expense and costs from the PEER, as further discussed below, partially offset by lower other operating expenses, higher revenues from regulated investment programs and higher weather-adjusted customer usage and demand.

Revenues —

The $237 million increase in total revenues resulted from the following sources:
For the Years Ended December 31,
Revenues by Type of Service20232022Increase (Decrease)
(In millions)
Distribution services$5,372 $5,261 $111 
Generation sales:
Retail5,214 4,841 373 
Wholesale228 494 (266)
Total generation sales5,442 5,335 107 
Other224 205 19 
Total Revenues$11,038 $10,801 $237 

Distribution services revenues increased $111 million in 2023, as compared to 2022, primarily resulting from higher rider revenues associated with certain investment programs, higher weather-adjusted customer usage and demand, lower customer refunds and credits associated with the PUCO-approved Ohio Stipulation and other rider rate adjustments at the Pennsylvania Companies, which have no material impact to current period earnings, partially offset by lower customer usage as a result of the weather and lower recovery of transmission expenses.

Distribution services by customer class are summarized in the following table:
For the Years Ended December 31,
(In thousands)ActualWeather-Adjusted
Electric Distribution MWh Deliveries20232022Increase (Decrease)20232022Increase
Residential52,216 55,995 (6.7)%55,908 55,081 1.5 %
Commercial(1)
34,891 36,317 (3.9)%36,180 36,024 0.4 %
Industrial55,541 55,169 0.7 %55,541 55,169 0.7 %
Total Electric Distribution MWh Deliveries142,648 147,481 (3.3)%147,629 146,274 0.9 %
(1) Includes street lighting.

Residential and commercial distribution deliveries were impacted by lower customer usage as a result of the weather. Heating degree days in 2023 were 14% below 2022 and 15% below normal. Cooling degree days in 2023 were 23% below 2022 and 15% below normal. Increases in industrial distribution deliveries were primarily from oil and gas extraction, mining, and transportation equipment manufacturing, partially offset by decreases in deliveries to plastic and rubber manufacturing and chemical manufacturing.

Compared to pre-pandemic levels in 2019, weather-adjusted residential distribution deliveries in 2023 increased 4.3%, while commercial and industrial deliveries decreased 4.1% and 0.2%, respectively.






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The following table summarizes the price and volume factors contributing to the $107 million increase in generation revenues in 2023, as compared to 2022:
Source of Change in Generation RevenuesIncrease (Decrease)
 (In millions)
Retail: 
Change in sales volumes$(198)
Change in prices571 
 373 
Wholesale:
Change in sales volumes(131)
Change in prices(94)
Capacity revenue(41)
 (266)
Change in Generation Revenues$107 

Retail generation sales, other than those in West Virginia, have no material impact to FirstEnergy's earnings. The decrease in retail generation sales volumes was primarily due to lower usage as a result of the weather and increased customer shopping in Pennsylvania, Total generation provided by alternative suppliers as a percentage of total MWh deliveries in 2023, as compared to 2022, increased to 62% from 60% in Pennsylvania. The increase in retail generation prices primarily resulted from higher non-shopping generation auction rates.

Wholesale generation revenues decreased $266 million in 2023, as compared to 2022, primarily due to lower capacity revenues, sales volumes and market prices. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to current period earnings.

Operating Expenses —

Total operating expenses increased $193 million primarily due to the following:

•Fuel expense decreased $192 million in 2023, as compared to 2022, primarily due to lower generation output and unit costs. However, due to the ENEC, fuel expense has no material impact on current period earnings.

•Purchased power costs increased $245 million in 2023, as compared to 2022, primarily due to increased prices, partially offset by lower capacity expenses and decreased volumes as described above.
Source of Change in Purchased PowerIncrease (Decrease)
 (In millions)
Purchases
Change due to unit costs$419 
Change due to volumes(114)
 305 
 
Capacity expense(60)
Change in Purchased Power Costs$245 


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•Other operating expenses decreased $40 million in 2023, as compared to 2022, primarily due to:

•Lower other operating and maintenance expenses of $47 million, primarily associated with lower labor costs and fewer regulated generation planned outages;
•Lower vegetation management expenses of $86 million, including accelerated work during 2022;
•Lower network transmission expenses of $46 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings; and
•Lower uncollectible expenses of $46 million of which $24 million was deferred for future recovery, resulting in no material impact on current period earnings;
partially offset by:
•Lump sum compensation and severance benefits of $42 million associated with the PEER program and involuntary separations in 2023, as further discussed below;
•Higher vegetation management in West Virginia, energy efficiency and other state mandated program costs of $58 million, which are deferred for future recovery, resulting in no material impact on current period earnings; and
•Higher storm expenses of $85 million, which was all deferred for future recovery, resulting in no material impact on current period earnings.

•Depreciation expense increased $54 million in 2023, as compared to 2022, primarily due to a higher asset base.

•Deferral of regulatory asset decreased $106 million in 2023, as compared to 2022, primarily due to:

•$100 million decrease due to the absence of a return of certain Tax Act savings to Pennsylvania customers in 2022;
•$97 million net decrease due to lower generation and transmission related deferrals, and
•$51 million decrease due to the absence of the customer refunds associated with the Ohio Stipulation;
partially offset by:
•$91 million increase due to higher deferral of storm related expenses;
•$28 million increase due to higher energy efficiency related deferrals;
•$14 million related to net increases in other deferrals; and
•$9 million increase due to lower vegetation related amortizations.

•General taxes increased $20 million in 2023, as compared to 2022, primarily due to higher gross receipts taxes and Ohio property taxes, partially offset by lower Ohio kWh taxes.

Other Expense —

Other expense increased $345 million in 2023, as compared to 2022, primarily due to lower net pension and OPEB non-service credits, a $28 million change in pension and OPEB mark-to-market adjustments, higher net interest expense associated with new long-term issuances and higher short-term borrowings, and a charge from an environmental settlement agreement requiring a $10 million contribution to the EPA associated with a former generation plant of OE.

Income Taxes

Regulated Distribution’s effective tax rate was 18.4% and 20.8% for 2023 and 2022, respectively.

Regulated Transmission — 2023 Compared with 2022

Regulated Transmission’s earnings attributable to FE from continuing operations increased $153 million in 2023, as compared to 2022, primarily due to the absence of a reserve for customer refunds and the reclassification of certain transmission capital assets that are not expected to be recoverable resulting from the FERC Audit that was recognized in the third quarter of 2022, as further discussed below, and an adjustment associated with the recovery of certain costs during 2023. Additionally, earnings increased as a result of regulated capital investments that increased rate base, which is partially offset by the 19.9% minority equity interest sale in FET that closed in May 2022.

Revenues —

Total revenues increased $186 million in 2023, as compared to 2022, primarily due to the absence of a reserve for customer refunds associated with the FERC Audit, as further discussed below, a true-up adjustment for the recovery of certain transmission formula rate operating costs during 2023 and a higher rate base.

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Revenues by transmission asset owner are shown in the following table:
For the Years Ended December 31,
Revenues by Transmission Asset Owner20232022Increase
(In millions)
ATSI$968 $912 $56 
TrAIL284 275 9 
MAIT395 340 55 
JCP&L205 203 2 
MP, PE and WP202 138 64 
Total Revenues$2,054 $1,868 $186 
    
Operating Expenses —

Total operating expenses decreased $152 million in 2023, as compared to 2022, primarily due to the absence of the reclassification of certain transmission capital assets to operating expenses as a result of the FERC Audit, as further discussed below, partially offset by higher depreciation and property tax expenses from a higher asset base. Other than the write-off of nonrecoverable transmission assets, nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.

Other Expense —

Total other expense increased $75 million in 2023, as compared to 2022, primarily due to lower affiliated company interest income at FET, lower net pension and OPEB non-service credits and higher net financing costs due to the new debt issuances at MAIT and ATSI.

Income Taxes —

Regulated Transmission’s effective tax rate was 23.3% and 21.8% for 2023 and 2022, respectively.
Corporate/Other — 2023 Compared with 2022

Financial results from Corporate/Other resulted in a $781 million decrease in losses attributable to FE from continuing operations for 2023 compared to 2022, primarily due to lower income tax expense, lower interest and debt redemption expenses from the redemption of certain FE notes, as further discussed below, and lower affiliated company borrowings.

Lower income tax expense was primarily due to the absence of an income tax charge of $752 million in 2022, representing the deferred tax liability associated with the deferred tax gain on the 19.9% sale of FET membership interest to Brookfield, and a 2023 tax benefit of $65 million, net of a reserve for uncertain tax positions, from the reduction of state income taxes and partial release of a valuation allowance for the expected utilization of state net operating losses based on an assessment of regulated business operation and the composition of a state tax return filing group, partially offset by a $58 million tax charge in 2023 associated with a true-up adjustment associated with the deferred tax gain on the 19.9% sale of FET membership interest.

Financial results compared to the same period of 2022 also reflect higher investment earnings on corporate-owned life insurance policies and FEV’s interests in Signal Peak and lower debt redemption costs, partially offset by expenses associated with the cancellation of certain sponsorship agreements in 2023, higher investigation and other related costs associated with government investigations, a charge associated with an update to the McElroy’s Run ARO, lower pension and OPEB non-service credits and higher interest from the 2026 Convertible Notes issuance.
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 Utilities 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

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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 December 31, 2023 and 2022, and the changes during the year 2023:
As of December 31,
Net Regulatory Assets (Liabilities) by Source20232022Change
 (In millions)
Customer payables for future income taxes$(2,382)$(2,463)$81 
Spent nuclear fuel disposal costs(83)(83)— 
Asset removal costs(652)(675)23 
Deferred transmission costs286 50 236 
Deferred generation costs572 235 337 
Deferred distribution costs247 164 83 
Storm-related costs799 683 116 
Energy efficiency program costs198 94 104 
New Jersey societal benefit costs79 94 (15)
Vegetation management costs102 63 39 
Other(11)24 (35)
Net Regulatory Liabilities included on the Consolidated Balance Sheets$(845)$(1,814)$969 

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 Utilities 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.

Deferred distribution costs - Primarily relates to the Ohio Companies' deferral of certain distribution-related expenses, including interest (amortized through 2034).

Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $254 million and $206 million are currently being recovered through rates as of December 31, 2023 and 2022, respectively.


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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, the Pennsylvania Companies' 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 and WP/PE (amortized through 2024, 2030 and 2036, respectively).

The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2023 and 2022, of which approximately $371 million and $511 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 aAs of December 31,
Current Return20232022Change
(In millions)
Deferred transmission costs$6 $8 $(2)
Deferred generation costs432 262 170 
Deferred distribution costs68 27 41 
Storm-related costs602 568 34 
Pandemic-related costs35 45 (10)
Vegetation management21 52 (31)
Other33 35 (2)
Regulatory Assets Not Earning a Current Return$1,197 $997 $200 
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.

Investments in 2023 by business segment are included below:
Business Segment
2023
Actual
 (In millions)
Regulated Distribution(1)
$1,852 
Regulated Transmission1,781 
Corporate/Other114 
Total$3,747 
(1) Includes capital expenditures and capital-like investments that earn a return.

Beginning in 2024, FirstEnergy changed its reportable segments to include Distribution, which will consist of the Ohio Companies and FE PA; Integrated, which will consist of MP, PE and JCP&L; and Stand-Alone Transmission, which will consist of FE's ownership in FET and KATCo. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo. Corporate/Other will reflect corporate support and other support costs not charged or attributable to the Utilities or Transmission Companies, including FE's retained Pension and OPEB assets and liabilities of former subsidiaries, interest

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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.
Capital investment forecasts for the years ended 2024, 2025, 2026, 2027, and 2028 by business segment are included below:
Business Segment
2024
Forecast
2025 Forecast
2026 Forecast
2027 Forecast
2028 Forecast
 (In millions)
Distribution$1,200 $1,300 $1,500 $1,700 $1,800 
Stand-Alone Transmission1,400 1,500 1,600 1,700 1,900 
Integrated(1)
1,600 1,800 2,000 2,200 2,400 
Corporate/Other100 100 100 100 100 
Total$4,300 $4,700 $5,200 $5,700 $6,200 
(1) Includes capital expenditures and capital-like investments that earn a return.

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 majority of the purchase price is expected to be paid in cash upon closing, and the remainder will be payable by the issuance of a promissory note, which is expected to be repaid by the end of 2024. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the PPUC. In addition, pursuant to the FET P&SA II, FirstEnergy made the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, making FE PA a new, single operating entity. In addition to merging each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies, (i) WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and (ii) PN and ME contributed their respective Class B equity interests of MAIT to FE. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and serves an area with a population of approximately 4.5 million. FE PA operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.

Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending 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.

On May 9, 2023, FirstEnergy announced a voluntary retirement program for eligible non-bargaining employees, known as the PEER. More than 65% of eligible employees, totaling approximately 450 employees, accepted the PEER, which included lump sum compensation equivalent to severance benefits, healthcare continuation costs and a temporary pension enhancement. Most PEER participating employees departed in 2023. The temporary pension enhancement and healthcare continuation costs are classified as special termination costs within net periodic benefit costs (credits). In addition to the PEER, FirstEnergy notified and involuntarily separated approximately 90 employees on May 9, 2023. Management expects the cost savings resulting from these initiatives to support FirstEnergy’s growth plans.

As of December 31, 2023, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to accounts payable, current portion of long-term debt, short-term borrowings and accrued interest, taxes, and compensation and

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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 Utilities, and the Transmission Companies 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. KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 2024.

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;
•Transmission Companies, $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 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.


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FirstEnergy had $775 million and $100 million of outstanding short-term borrowings as of December 31, 2023 and 2022, respectively. FirstEnergy’s available liquidity from external sources as of February 5, 2024, was as follows:
Revolving Credit FacilitiesMaturityCommitmentAvailable Liquidity
  (In millions)
FEOctober 2027$1,000 $267 
FETOctober 20281,000 $800 
Ohio CompaniesOctober 2027800 $800 
FE PA(1)
October 2027950 $950 
JCP&LOctober 2027500 $299 
MP and PEOctober 2027400 $400 
Transmission CompaniesOctober 2027850 $850 
KATCo(2)
October 2027150 $150 
 Subtotal$5,650 $4,516 
Cash and Cash equivalents— 118 
 Total$5,650 $4,634 
(1) Effective January 1, 2024, FE PA succeeded the Pennsylvania Companies as the borrower under the Pennsylvania Companies' revolving credit facility.
(2) KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 2024.

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 December 31, 2023:
Individual BorrowerRegulatory Debt LimitationsCredit Facility LimitationsDebt-to-Total-Capitalization Ratio
 (In millions)
FEN/A$1,000 
N/A(3)
ATSI(1)

$500 350 40.7 %
CEI(1)

500 300 47.4 %
FETN/A1,000 64.1 %
JCP&L(1)

500 500 38.7 %
KATCo(1)

200 150 
N/A(4)
ME(1)(2)

500 350 50.7 %
MAIT(1)

400 350 39.2 %
MP(1)

500 250 55.4 %
OE(1)

500 300 50.5 %
PN(1)(2)

300 300 53.6 %
Penn(1)(2)

150 100 46.1 %
PE(1)

150 150 50.5 %
TE(1)

300 200 47.9 %
TrAIL(1)

400 150 39.6 %
WP(1)(2)

300 200 51.5 %
(1) Includes amounts which may be borrowed under the regulated companies’ money pool.
(2) ME, PN, Penn, and WP merged with and into FE PA effective January 1, 2024. FE PA's regulatory debt limitation is $1.25 billion, and its credit facility limitation is $950 million.
(3) 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 December 31, 2023 was 4.45.
(4) KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 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 December 31, 2023, FirstEnergy had $4 million in outstanding LOCs.

Revolving Credit FacilityLOC Availability
as of December 31, 2023
(In millions)
FE$100 
FET100 
Ohio Companies150 
Pennsylvania Companies(1)
200 
JCP&L100 
MP and PE100 
Transmission Companies200 
KATCo(2)
35 
(1) ME, PN, Penn, and WP merged with and into FE PA effective January 1, 2024.
(2) KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 2024.

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 December 31, 2023, 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 utility 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. 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 RatesRegulated Companies’ Money PoolUnregulated Companies’ Money Pool
2023202220232022
For the Years Ended December 31, 6.30 %2.27 %6.01 %2.14 %


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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. Effective January 1, 2024, as a result of the PA Consolidation, the ratings agencies withdrew their prior ratings for ME, PN, Penn and WP. The following table displays FE’s and its subsidiaries’ credit ratings as of February 5, 2024:
Corporate Credit RatingSenior SecuredSenior Unsecured
Outlook/CreditWatch(1)
IssuerS&PMoody’sFitchS&PMoody’sFitchS&PMoody’sFitchS&PMoody’sFitch
FEBBB-Ba1BBB-———BB+Ba1BBB-P
RUR(2)
S
AGCBB+Baa2BBB——————PSS
ATSIBBBA3BBB———BBBA3BBB+PSS
CEIBBBBaa3BBBA-Baa1A-BBBBaa3BBB+PSS
FE PABBBA3BBBA-
A1(3)
A-BBB
A3(3)
BBB+PSS
FETBBB-Baa2BBB-———BB+Baa2BBB-PSS
JCP&LBBBA3BBB———BBBA3BBB+PSS
KATCo—A3BBB———————SS
MAITBBBA3BBB———BBBA3BBB+PSS
MPBBBBaa2BBBA-A3A-BBBBaa2—SSS
OEBBBA3BBBA-A1A-BBBA3BBB+PSS
PEBBBBaa2BBBA-A3A-———SSS
TEBBBBaa2BBBA-A3A-———PSS
TrAILBBBA3BBB———BBBA3BBB+PSS
(1) S = Stable, P = Positive, RUR= Ratings Under Review for upgrade
(2) On November 9, 2023, Moody's placed FE's rating under review for upgrade
(3) Legacy debt issued under FMBs by FE PA's predecessors (WP and Penn) are rated A1, Stable at Moody's. In addition, legacy senior unsecured debt issued by FE PA's predecessors (ME and PN) are rated A3, Stable at Moody's. Once secured or unsecured debt is issued by FE PA, Moody's will assign a respective credit rating.

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 December 31, 2023, FirstEnergy could incur approximately $880 million of incremental interest expense or incur an approximate $2.2 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 required by the 2021 Credit Facilities.

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Cash Requirements and Commitments

FirstEnergy has certain obligations and commitments to make future payments under contracts, including contracts executed in connection with certain of the planned construction expenditures.
As of December 31, 2023 (Undiscounted): Total20242025-20262027-2028Thereafter
(In millions)
Long-term debt(1)
$24,253 $1,246 $4,899 $4,456 $13,652 
Short-term borrowings775 775 — — — 
Interest on long-term debt10,324 1,015 1,764 1,426 6,119 
Operating leases(2)
261 54 90 70 47 
Finance leases(2)
19 4 8 7 — 
Fuel and purchased power(3)
1,488 216 427 335 510 
Committed investments(4)
4,784 1,652 1,827 1,305 — 
Pension funding(5)
910 — — 260 650 
Total$42,814 $4,962 $9,015 $7,859 $20,978 
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases.
(2) See Note 8, "Leases," of the Notes to Consolidated Financial Statements
(3) Based on estimated annual amounts under contract with fixed or minimum quantities
(4) Amounts represent committed capital expenditures and other capital-like investments that earn a return.
(5) As discussed further below, FirstEnergy does not expect to have a required contribution to the pension plan until 2028.

Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. Although actual amounts will be determined by future customer behavior, consumption levels and power prices, management currently estimates these cash outlays will be approximately $4 billion in 2024.

The table above also excludes AROs, reserves for litigation, injuries and damages and environmental remediation since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year and/or the application of the corporate AMT which, as further discussed below, is uncertain and subject to the issuance of future U.S. Treasury regulations.

FirstEnergy’s pension funding policy is based on actuarial computations using the projected unit credit method. On May 12, 2023, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan. 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.

Changes in Cash Position

As of December 31, 2023, FirstEnergy had $137 million of cash and cash equivalents and $42 million of restricted cash compared to $160 million of cash and cash equivalents and $46 million of restricted cash as of December 31, 2022, on the Consolidated Balance Sheets.

The following table summarizes the major classes of cash flow items:
For the Years Ended December 31,
(In millions)202320222021
Net cash provided from operating activities$1,387 $2,683 $2,811 
Net cash used for investing activities(3,652)(3,076)(2,559)
Net cash provided from (used for) financing activities2,238 (912)(542)
Net change in cash, cash equivalents and restricted cash(27)(1,305)(290)
Cash, cash equivalents, and restricted cash at beginning of period206 1,511 1,801 
Cash, cash equivalents, and restricted cash at end of period$179 $206 $1,511 



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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.

Net cash provided from operating activities was $1,387 million during 2023, $2,683 million during 2022, and $2,811 million during 2021. The decrease in cash from operating activities in 2023 from 2022 is primarily due to:

•A $750 million cash contribution to the qualified pension plan in the second quarter of 2023;
•Higher payments, primarily on generation energy purchases for certain customers, net of related customer receivable receipts;
•The return of cash collateral to certain generation suppliers that serve shopping customers that was previously received as a result of changes in power prices;
•Lower net transmission revenue collection based on the timing of formula rate collections; and
•Lower distribution sales revenue as a result of mild weather conditions, as further discussed above;
partially offset by:
•Higher returns from regulated distribution and transmission capital investments; and
•Lower customer refunds and credits associated with the PUCO-approved Ohio Stipulation.

FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2023, 2022 and 2021:
For the Years Ended December 31,
(In millions)202320222021
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations$(21)$— $44 
Loss (gain) on disposal, net of tax 21 — (47)
    Cash Flows From Investing Activities

Cash used for investing activities in 2023 principally represented cash used for capital investments. The following table summarizes cash used for (received from) investing activities for the years ended 2023, 2022 and 2021:
For the Years Ended December 31,
Investing Activities202320222021
(In millions)
Capital Investments:
Regulated Distribution$1,631 $1,605 $1,437 
Regulated Transmission1,610 1,192 958 
Corporate/Other115 51 92 
Proceeds from sale of Yards Creek— — (155)
Asset removal costs274 213 226 
Other22 15 1 
$3,652 $3,076 $2,559 
Cash used for investing activities during 2023 increased $576 million, compared to 2022, primarily due to higher planned capital investment spend at the Regulated Transmission segment.
Cash Flows From Financing Activities
Cash provided from (used for) financing activities was $2,238 million, $(912) million, and $(542) million in 2023, 2022, and 2021, respectively. The following table summarizes financing activities for the years ended 2023, 2022, and 2021.

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For the Years Ended December 31,
Financing Activities202320222021
 (In millions)
New Issues   
Unsecured notes$2,550 $300 $1,750 
FMBs600 400 200 
Senior secured notes— — 150 
 3,150 700 2,100 
Redemptions / Repayments   
Unsecured notes(494)(2,737)(400)
Pollution control revenue bonds— — (74)
FMBs— (200)— 
Senior secured notes(43)(68)(58)
 (537)(3,005)(532)
Proceeds from FET minority interest sale, net of transaction costs— 2,348 — 
Distributions to FET minority interest(72)(21)— 
Capital Call from FET minority interest— 9 — 
Common stock issuance— — 1,000 
Short-term borrowings, net675 100 (2,200)
Common stock dividend payments(906)(891)(849)
Other(72)(152)(61)
$2,238 $(912)$(542)

During the year ended December 31, 2023, FirstEnergy had the following redemptions and issuances:
CompanyTypeRedemption/Issuance DateInterest RateMaturityAmount
(In millions)		Description
Redemptions(1)
MEUnsecured NotesMarch, 20233.50%2023$300ME redeemed unsecured notes that became due.
FEUnsecured NotesMay, 20237.38%2031$194FE repurchased approximately $194 million of the principal amount of its 2031 Notes through the open market for $228 million, including a premium of approximately $34 million ($27 million after-tax). In addition, FE recognized approximately $2 million ($1 million after-tax) of deferred cash flow hedge losses associated with the FE debt redemptions.
Issuances
WPFMBsJanuary, 20235.29%2033$50Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MAITUnsecured NotesFebruary, 20235.39%2033$175Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MEUnsecured NotesMarch, 20235.20%2028$425Proceeds were used to repay short-term borrowings, including borrowings incurred to repay, at maturity, the $300 million aggregate principal amount of ME's 3.50% unsecured notes due March 15, 2023, to finance capital expenditures and for other general corporate purposes.
PNUnsecured NotesMarch, 20235.15%2026$300Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
ATSIUnsecured NotesMay, 20235.13%2033$150Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
FEUnsecured Convertible NotesMay, 20234.00%2026$1,500Proceeds were used to repay short-term borrowings, to repurchase a portion of its 2031 Notes, to fund the qualified pension plan and for other general corporate purposes.
PEFMBsSeptember, 20235.64%2028$100Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
PEFMBsSeptember, 20235.73%2030$50Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MPFMBsSeptember, 20235.85%2034$400Proceeds are to be used for repaying short-term and long-term debt, including MP’s $400 million 4.1% FMBs due April 15, 2024, to finance capital expenditures and for other general corporate purposes.
(1) Excludes principal payments on securitized bonds.


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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.

Convertible Notes

As discussed above, on May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, with a fixed interest rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. However, FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date. The 2026 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $1.48 billion, net of issuance costs.

Prior to the close of business on the business day immediately preceding February 1, 2026, the 2026 Convertible Notes will be convertible at the option of the holders only under the following conditions:

•During any calendar quarter, if the last reported sale price of FE’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;
•During the 5 consecutive business day period immediately after any 10 consecutive trading day period in which the trading price per $1,000 principal amount of the 2026 Convertible Notes for each trading day of such 10 trading day period was less than 98% of the product of the last reported sale price of FE’s common stock and the conversion rate on each such trading day; or
•Upon the occurrence of certain corporate events specified in the indenture governing the 2026 Convertible Notes.

On and after February 1, 2026, until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2026 Convertible Notes may convert all or any portion of their 2026 Convertible Notes at their option at any time at the conversion rate then in effect, irrespective of these conditions. FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash up to the aggregate principal amount of the 2026 Convertible Notes being converted and by paying cash or delivering shares of FE’s common stock (or a combination of each), at its election, of its conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted.

The conversion rate for the 2026 Convertible Notes will initially be 21.3620 shares of FE’s common stock per $1,000 principal amount of the 2026 Convertible Notes (equivalent to an initial conversion price of approximately $46.81 per share of FE’s common stock). The initial conversion price of the 2026 Convertible Notes represents a premium of approximately 20% over the last reported sale price of FE’s common stock on the New York Stock Exchange on May 1, 2023. The conversion rate and the corresponding conversion price will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.

If FE undergoes a fundamental change (as defined in the relevant indenture), subject to certain conditions, holders of the 2026 Convertible Notes may require FE to repurchase for cash all or any portion of their 2026 Convertible Notes at a repurchase price equal to 100% of the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date (as defined in the relevant indenture). In addition, if certain fundamental changes occur, FE may be required, in certain circumstances, to increase the conversion rate for any 2026 Convertible Notes converted in connection with such fundamental changes by a specified number of shares of its common stock.

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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 FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2023, was approximately $815 million, as summarized below:
Guarantees and Other AssurancesMaximum Exposure
 (In millions)
FE's Guarantees on Behalf of its Consolidated Subsidiaries(1)
Deferred compensation arrangements$425 
Vehicle leases75 
Other15 
 515 
FE's Guarantees on Other Assurances
Surety Bonds(2)
181 
Deferred compensation arrangements115 
LOCs4 
 300 
Total Guarantees and Other Assurances$815 
(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.

As of December 31, 2023, $89 million of net cash collateral has been posted by FE or its subsidiaries and is included in "Prepaid taxes and other current assets" on FirstEnergy's Consolidated Balance Sheets. FE or its subsidiaries are holding $27 million of net cash collateral as of December 31, 2023, 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 December 31, 2023:
Potential Collateral ObligationsUtilities and Transmission CompaniesFETotal
(In millions)
Contractual Obligations for Additional Collateral
Upon Further Downgrade$62 $— $62 
Surety Bonds (collateralized amount)(1)
86 79 165 
Total Exposure from Contractual Obligations$148 $79 $227 
(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 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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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, including 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 December 31, 2023, FirstEnergy has a net asset of $3 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings.

Equity Price Risk

As of December 31, 2023, the FirstEnergy pension plan assets were allocated approximately as follows: 26% in public equity securities, 26% in fixed income securities, 6% in hedge funds, 2% in insurance-linked securities, 10% in real estate funds, 19% in private equity and debt funds and 11% in cash and short-term securities. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2028, which based upon 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 December 31, 2023, FirstEnergy's OPEB plan assets were allocated approximately as follows: 50% in equity securities, 31% in fixed income securities and 19% in cash and short-term securities. See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans.

During 2023, FirstEnergy's OPEB plan assets have gained approximately 14.7% as compared to an annual expected return on plan assets of 7.0%. During the second quarter of 2023, FirstEnergy remeasured its pension plan assets as of April 30, 2023 as a result of the voluntary contribution discussed below. Actual returns on the pension assets through the date of the voluntary contribution were approximately 7.7%, as compared to expected return on assets of 2.67% (8.0% on an annualized basis). From May 1, 2023, through December 31, 2023, the pension plan assets gained approximately 3.0% as compared to expected return on assets of 5.3% (8.0% on an annualized basis).

Interest Rate Risk

FirstEnergy’s exposure to fluctuations in market interest rates is reduced since all long-term debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities.
Comparison of Carrying Value to Fair Value as of December 31, 2023
Year of Maturity or Notice of Redemption20242025202620272028There-afterTotalFair Value
(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income$— $— $— $— $— $276 $276 $276 
Average interest rate— %— %— %— %— %2.6 %2.6 %
Liabilities:
Long-term Debt:
Fixed rate$1,246 $2,023 $2,876 $2,003 $2,453 $13,653 $24,254$23,003 
Average interest rate4.7 %3.8 %4.0 %4.2 %3.8 %4.6 %4.4 %

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 (which occurred during the second quarter of 2023). 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.


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

On May 12, 2023, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan. The size of the voluntary contribution made on May 12, 2023, in relation to total pension assets triggered a remeasurement of the pension plan. FirstEnergy elected the practical expedient to remeasure pension plan assets and obligations as of April 30, 2023, which is the month-end closest to the date of the voluntary contribution.

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. The discount rate used to measure pension obligations was 4.94% as of April 30, 2023 and 5.23% as of December 31, 2022 compared to 5.05% as of December 31, 2023. The discount rate used to measure OPEB obligations was 5.16% as of December 31, 2022 as compared to 4.97% as of December 31, 2023.

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 increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending 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 credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and require 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 utilities, 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

On August 16, 2022, President Biden signed into law the IRA of 2022, which, 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 net operating losses 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 it will be subject to the AMT beginning in 2023. Accordingly, FirstEnergy made a first quarter estimated payment of AMT of approximately $49 million in April 2023. In June 2023, the U.S. Treasury issued additional guidance that eliminated the requirement of corporations to include AMT in quarterly estimated tax payments, pending further guidance on the application and administration of AMT. Therefore, as a result of guidance issued to date, the current forecast of AMT obligation, and the amount of AMT already paid in April 2023, FirstEnergy did not make any additional AMT payments for the 2023 tax year. Until final U.S. Treasury regulations are issued, the

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amount of AMT FirstEnergy pays could be significantly different than current estimates or it may not be a payer at all. 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 discussed above, FirstEnergy expects to close on the sale of an additional 30% interest in FET in 2024, at which time FirstEnergy expects to realize an approximate $7.5 billion tax gain from the combined sale of 49.9% of the membership interests of FET for consideration received and recapture of negative tax basis in FET. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards, as further discussed below, which will be used to offset a majority of the tax gain from the FET sale and expected taxable income in 2024, however due to certain limitations on utilization enacted in the Tax Act, a portion of the NOL will carry into 2025 and possibly beyond. As a result of the expected additional 30% sale in FET, FirstEnergy recognized a charge to income tax expense in the fourth quarter of 2022 of approximately $752 million, representing the deferred tax liability associated with the deferred tax gain on the initial 19.9% sale of FET that closed in May 2022, such deferred gain consisting of consideration received on the sale and the recapture of estimated negative tax basis in FET impacted by taxable income and loss among other factors. In the fourth quarter of 2023, FirstEnergy recognized a charge to income tax expense of approximately $58 million as a true-up of the deferred tax liability associated with the deferred tax gain.

STATE REGULATION

Each of the Utilities' 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.

The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2023:
CompanyRates Effective For CustomersAllowed Debt/EquityAllowed ROE
CEIMay 2009
51% / 49%
10.5%
ME(1)
January 2017
48.8% / 51.2%
Settled(2)
MPFebruary 2015
54% / 46%
Settled(2)
JCP&LNovember 2021
48.6% / 51.4%
9.6%
OEJanuary 2009
51% / 49%
10.5%
PE (West Virginia)February 2015
51% / 49%
Settled(2)
PE (Maryland)October 2023
47% / 53%
9.5%
PN(1)
January 2017
47.4% / 52.6%
Settled(2)
Penn(1)
January 2017
49.9% / 50.1%
Settled(2)
TEJanuary 2009
51% / 49%
10.5%
WP(1)
January 2017
49.7% / 50.3%
Settled(2)
(1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. Additionally, on January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity, and will operate under the rate districts of the former Pennsylvania Companies.
(2) Commission-approved settlement agreements did not disclose ROE rates.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of October 19, 2023. 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.

On March 22, 2023, PE filed a base rate case with the MDPSC, utilizing a test year based on twelve months of actual 2022 data. The base rate case request included an annual increase in base distribution rates of $50.4 million, 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. The rate case additionally requested approval to continue an EDIS to fund three service reliability and resiliency programs, two new proposed programs to assist low-income customers and cost recovery of certain expenses associated with PE’s pilot electric vehicle charger program and its COVID-19 pandemic response. On October 18, 2023, the MDPSC approved an annual increase in base distribution rates of $28 million, effective October 19,

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2023. The order denied PE’s request to establish a pension/OPEB regulatory asset (or liability), allowed recovery of most COVID-19 deferred costs; and rejected the continuation of PE’s EDIS, as PE's reliability has improved such that the surcharge recovery mechanism is no longer merited at this time. The MDPSC also ordered an independent audit of certain allocations from FESC to PE and denied recovery of approximately $12 million in rate base associated with certain corporate support costs recorded to capital accounts resulting from the FERC Audit. On January 3, 2024, the MDPSC issued an order granting PE’s request for reconsideration and increased PE’s allowed distribution rates by another $0.7 million.

The EmPOWER Maryland program requires 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. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance. 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. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Consistent with a December 29, 2022, order by the MDPSC phasing out the ability of Maryland utilities to earn a return on EmPOWER investments, PE will be required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025 and 100% in 2026. Notwithstanding the order to phase out PE’s ability to earn a return on its EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and 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 amortized balances was extended through the end of 2031. Additionally at the direction of the MDPSC, PE together with other Maryland utilities are 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 $310 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 $310 million scenario for most programs, with some modifications.

On April 17, 2023, PE submitted a proposal to the MDPSC seeking approval to end its PPA with the Warrior Run generating station. The PPA for Warrior Run was a requirement of the Public Utility Regulatory Policies Act of 1978. PE’s Maryland customers currently pay a surcharge on their electric bill in connection with the Warrior Run PPA, which fluctuates from year to year based on the difference between what PE pays for the output of the plant and what PE is able to recover by reselling that output into PJM. PE negotiated a termination of the PPA, which the MDPSC approved on June 21, 2023, and became effective June 28, 2023, requiring it to pay Warrior Run a fixed amount of $51 million annually through 2029, for a total of $357 million. During the second quarter of 2023, a liability was established for the $357 million termination fee, of which $55 million was included in “Other current liabilities” and $302 million in “Other non-current liabilities”, and as the cost of the termination fee will be recovered through the current surcharge, an offsetting regulatory asset was established on FirstEnergy’s Consolidated Balance Sheets, and results in no impact to FirstEnergy’s or PE’s current or future earnings and is expected to result in savings for PE’s Maryland customers. On July 26, 2023, the MDPSC approved the change in surcharge, effective August 1, 2023, after previously approving the termination of the agreement.

NEW JERSEY

JCP&L operates under NJBPU approved rates that took effect as of January 1, 2021, and were effective for customers as of November 1, 2021. 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.

On March 16, 2023, JCP&L filed a base rate case with the NJBPU, utilizing a test year based on six months of actual data for the second half of calendar year 2022, and six months of forecasted data for the first half of calendar year 2023. The rate case requested an annual net increase in base distribution revenues of approximately $185 million, 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 2023 expense) and the actual annual amount each year using the delayed recognition method. JCP&L updated its base rate case in filings made on June 2, 2023 and August 7, 2023 to provide actual test-year data for the twelve months ended June 30, 2023, and update its proposed annual net increase in base rate distribution revenues to approximately $192 million. In addition to the above, JCP&L’s request includes, among other things, approval of two new proposed programs to assist low-income customers, cost recovery of certain investments and expenses associated with its electric vehicle and AMI programs, an update of its depreciation rates, modifications to its storm cost recovery, and tariff modifications to update standard construction costs. A procedural schedule was adopted with evidentiary hearings to be held the week of January 8, 2024. On October 17, 2023, JCP&L requested a suspension of the procedural schedule to enter into formal settlement discussions, which all parties agreed, and the administrative law judge granted the same day. On February 2, 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 provides for an $85 million annual base distribution revenues increase for JCP&L, which, if approved by the NJBPU, is expected to take effect February 15, 2024, and be effective for customers on June 1, 2024. Until those new rates become effective for customers, JCP&L would begin to amortize 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 will begin no later than March 1, 2024 and represents an approximate investment of $95 million. JCP&L expects to amend its pending EnergizeNJ petition upon receipt of NJBPU approval of the base rate case

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settlement, to include the second phase of its reliability improvement plan that is expected to address any remaining high-priority circuits not addressed in the first phase. The settlement did not include the request 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 the delayed recognition method, however, JCP&L has the ability to pursue in a future separate proceeding.

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 December 5, 2023, JCP&L filed a petition with the NJBPU for a six-month extension of EE&C Plan I, which was originally scheduled to end on June 30, 2024, but would end on December 31, 2024, with the extension. The proposed budget for the extension period would add approximately $69 million to the original program cost. Under the proposal, JCP&L would 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.

On March 6, 2023, the NJBPU issued final rules modifying its regulations to reflect its CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate 100% of CTA savings to customers; and (iii) exclude transmission assets of EDCs in the savings calculation. The final rules of practice were applied by JCP&L in its most recent base rate case filing described above.

On October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for distribution base rate increase. The settlement provided for a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which became effective for customers on November 1, 2021. The settlement additionally provided 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 filed its comments on July 31, 2023. The parties have filed responses.

On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 and continuing until the New Jersey Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. No moratorium on residential disconnections remains in effect for investor-owned electric utilities such as JCP&L. Legislation was enacted on March 25, 2022, prohibiting utilities from disconnecting electric service to customers that have applied for utility bill assistance before June 15, 2022 until such time as the state agency administering the assistance program makes a decision on the application and further requiring that all utilities offer a deferred payment arrangement meeting certain minimum criteria after the state agency’s decision on the application has been made. On July 17, 2023, JCP&L submitted a stand-alone filing to recover approximately $31 million, through October 1, 2023, in incremental costs and interest incurred during the COVID-19 pandemic.

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. FERC staff subsequently requested additional information on JCP&L’s application, which JCP&L provided. 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 MW. 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

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available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L anticipates submitting the second part of its two-part application in the first quarter of 2024.

On November 9, 2023, JCP&L filed a petition for approval of its second 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 costs of EnergizeNJ would be recovered through JCP&L's base rates via annual and semi-annual base rate adjustment filings. Public hearings have been requested but are not yet scheduled. JCP&L has requested that the NJBPU issue a final decision and order no later than May 22, 2024, based on a June 1, 2024, commencement date for EnergizeNJ. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from the NJBPU of the base rate case stipulation that was filed on February 2, 2024.

OHIO

The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies currently operate under ESP IV, effective June 1, 2016 and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 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 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. ESP V proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, with process enhancements designed to reduce costs to customers. ESP V also proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual revenue cap increases of $15 to $21 million per year, based on reliability performance, and Rider AMI for recovery of approved grid modernization investments. ESP V proposes new riders to support continued maintenance of the distribution system, including vegetation management and storm restoration operating expense. In addition, ESP V proposes four-year energy efficiency and peak demand reduction programs for residential and commercial customers, with cost recovery spread over eight years. ESP V further includes a commitment to spend $52 million in total over the eight-year term, without recovery from customers, on initiatives to assist low-income customers, education and incentives to help ensure customers have good experiences with electric vehicles. Hearings commenced on November 7, 2023 and concluded on December 6, 2023. On December 6, 2023, certain intervenors filed a motion requesting a limited stay of the Ohio Companies’ proposal to continue Rider DCR. The Ohio Companies contested the motion, which is pending.

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. This matter remains 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. Hearings are scheduled to commence on April 16, 2024. On January 22, 2024, OCC filed a motion requesting a stay of phase two. The Ohio Companies contested the motion, which is pending.

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

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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.

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 Rider DCR 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.

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.

In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR 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 Rider DCR 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.

On August 16, 2022, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6- related matters for a period of six months, which request was granted by the PUCO on August 24, 2022. On February 22, 2023, the U.S. Attorney for the Southern District of Ohio again requested that the PUCO stay the above pending HB-6 related matters for a period of six months, which request was granted by the PUCO on March 8, 2023. On August 10, 2023, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6-related matters for a period of six additional months, which was approved by the PUCO on August 23, 2023. On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order, 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 ESP V as well as Grid Mod I and Grid Mod II along with the investigations. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing. The four cases remain stayed in their entirety, including discovery and motions, and all related procedural schedules are vacated.

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.

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. This matter remains pending before the PUCO.

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See “Outlook - Other Legal Proceedings” below for additional details on the government investigations and subsequent 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 continue the current rate structure of ME, PN, Penn, and WP until the earlier of 2033 or in the fourth base rate case 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 to 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 June 25, 2021, the Pennsylvania Office of Consumer Advocate filed a complaint against Penn’s quarterly DSIC rate, disputing the recoverability of the Companies’ automated distribution management system investment under the DSIC mechanism. On January 26, 2022, the parties filed a joint petition for settlement that resolves all issues in this matter, which was approved by the PPUC without modification on April 14, 2022.

Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates. The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for accumulated deferred income taxes and state taxes. The PPUC issued the order as directed.

On March 6, 2023, FirstEnergy filed applications with the PPUC, NYPSC and FERC seeking approval to consolidate the Pennsylvania Companies into a new, single operating entity. The PA Consolidation includes, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the contribution of Class B equity interests of MAIT then held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale as further described above), (c) the formation of FE PA and (d) the merger of each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. On August 30, 2023, the parties filed a settlement agreement recommending that the PPUC approve the PA Consolidation subject to the terms of the settlement, which include among other things, $650 thousand over five years in bill assistance for income-eligible customers and the Pennsylvania Companies’ commitment to (i) not seek full distribution rate unification until the earlier of 10 years or in the fourth base rate case filed after January 1, 2025 and (ii) track and share with customers certain operational and administrative efficiency costs associated with the PA Consolidation. The PPUC, NYPSC and FERC approved FirstEnergy’s applications on December 7, 2023, November 16, 2023, and August 14, 2023, respectively. The transaction closed on January 1, 2024 making FE PA FirstEnergy's only regulated utility in Pennsylvania.

On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Minority 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 Minority Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority that it has 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 include among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement is currently pending PPUC approval.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective in February 2015. MP and PE recover net power supply costs, including

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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 updated annually.

On August 25, 2022, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $183.8 million beginning January 1, 2023, which represents a 12.2% increase to the rates then in effect. The increase was driven by an under recovery during the review period (July 1, 2021, to June 30, 2022) of approximately $145 million due to higher coal, reagent, and emission allowance expenses. This filing additionally addresses, among other things, the WVPSC’s May 2022 request for a prudence review of current rates. At a hearing on December 8, 2022, the parties in the case presented a unanimous settlement to increase rates by approximately $92 million, effective January 1, 2023, and carry over to MP and PE’s 2023 ENEC case, approximately $92 million at a carrying charge of 4%. In an order dated December 30, 2022, the WVPSC approved the settlement with respect to the proposed rate increase, but MP and PE rates remain subject to a prudence review in their 2023 ENEC case. The order also instructed MP to evaluate the feasibility of purchasing the 1,300 MW Pleasants Power Station and file a summary of the evaluation, which MP and PE filed on March 31, 2023. MP and PE provided the WVPSC with regular status reports throughout the second quarter of 2023 regarding the process of their evaluation. Subsequently, the owner of Pleasants entered into an agreement to sell Pleasants to an indirect wholly owned subsidiary of Omnis Global Technologies, LLC, which transaction closed on August 1, 2023. As a result, MP and PE ceased consideration of the possible purchase of Pleasants and on August 30, 2023, the WVPSC closed the proceeding.

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 represents 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 provides for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $255 million to be recovered through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover more than $50 million than the 2024 ENEC balance and a party elects to invoke a case filing. An order is expected by March 2024.

On November 22, 2021, MP and PE filed with the WVPSC their plan to construct 50 MWs of solar generation at five sites in West Virginia. The plan includes a tariff to offer solar power to West Virginia customers and cost recovery for MP and PE through a surcharge for any solar investment not fully subscribed by their customers. A hearing was held in mid-March 2022 and on April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, the requested tariff and requiring MP and PE to subscribe at least 85% of the planned 50 MWs before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. On April 24, 2023, MP and PE sought final tariff approval from the WVPSC for three of the five solar sites, representing 30 MWs of generation, and requested approval of a surcharge to recover any costs above the final approved tariff. 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 are 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 is expected in the first quarter 2024.

On March 2, 2023, the WVPSC ordered an audit of MP and PE focused on: (i) the lobbying and promotional/image building expenses, including those related to HB 6, incurred by MP and PE from 2018 to 2022 (ii) intra-corporate charges, (iii) the accounting for charges included in the ENEC cost recovery accounts of MP and PE during the same time period, and (iv) review and report on the findings, including those specific to MP and PE, set forth in the FERC Audit described below as well as a review and report of the responses by MP and PE thereto. The audit began in September 2023 and concluded with a filing of the report on December 28, 2023. The audit found no evidence that HB 6 related costs were included in the 2022 test year, and no errors or omission were identified that would materially affect lobbying and image building costs or expenses charged to the ENEC for the period 2018 to 2022. Additionally, there were several recommended adjustments and recommendations, however, none are expected to have a material effect on FirstEnergy, MP or PE. The report was evaluated as part of the ongoing base rate case.

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 includes the approximate $76 million requested in a depreciation case filed on January 13, 2023 and described more fully above, and amounts to support a new low-income customer advocacy program,

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storm restoration work and service reliability investments. New rates are expected to be effective by the end of March 2024. On January 23, 2024, MP, PE and various parties filed with a joint settlement agreement with the WVPSC, which recommends a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense. Additionally, the settlement includes 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 recover (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. An order is expected by the end of the first quarter of 2024 with new rates to be effective March 27, 2024.

On August 31, 2023, MP and PE filed its biennial review of their vegetation management program and surcharge. MP and PE have proposed an approximate $17 million increase in the surcharge rates, due to an under recovery in the prior two-year period and increased forecast costs. The case was unanimously settled by the parties on November 29, 2023, approved by the WVPSC on January 8, 2024, and the $17 million increase proposed by MP and PE went into effect on January 1, 2024. See “Outlook - Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.

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 Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP 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.

The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2023:
CompanyRates EffectiveCapital StructureAllowed ROE
ATSIJanuary 2015Actual (13-month average)10.38%
JCP&L
January 2020Actual (13-month average)10.20%
MPJanuary 2021Lower of Actual (13-month average) or 56% 10.45%
PE January 2021Lower of Actual (13-month average) or 56% 10.45%
WP(1)
January 2021Lower of Actual (13-month average) or 56% 10.45%
MAITJuly 2017
Lower of Actual (13-month average) or 60%
10.3%
TrAILJuly 2008Actual (year-end)
12.7%(2) / 11.7%(3)

(1) On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo
(2) TrAIL the Line and Black Oak Static Var Compensator
(3) All other projects

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 Utilities 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 Utilities 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 Utilities, 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

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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 $13 million of costs have been recovered as of December 31, 2023. 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 distribution utilities 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 $310 million of certain corporate support costs allocated to distribution capital assets. 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. FirstEnergy is actively participating in the appeal 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

On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. FirstEnergy submitted comments through the Edison Electric Institute and as part of a consortium of PJM Transmission Owners. In a supplemental rulemaking proceeding that was initiated on April 15, 2021, FERC requested comments on, among other things, whether to require utilities that have been members of an RTO for three years or more and that have been collecting an “RTO membership” ROE incentive adder to file tariff updates that would terminate collection of the incentive adder. Initial comments on the proposed rule were filed on June 25, 2021, and reply comments were filed on July 26, 2021. The rulemaking remains pending before FERC. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the supplemental proposed rule. 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.

Allegheny Power Zone Transmission Formula Rate Filings


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On October 29, 2020, MP, PE and WP filed tariff amendments with FERC to implement a forward-looking formula transmission rate, to be effective January 1, 2021. In addition, on October 30, 2020, KATCo filed a proposed new tariff to establish a forward-looking formula rate and requested that the new rate become effective January 1, 2021. In its filing, KATCo explained that while it currently owns no transmission assets, it may build new transmission facilities in the Allegheny zone, and that it may seek required state and federal authorizations to acquire transmission assets from PE and WP by January 1, 2022. These transmission rate filings were accepted for filing by FERC on December 31, 2020, effective January 1, 2021, subject to refund, pending further hearing and settlement procedures and were consolidated into a single proceeding. MP, PE and WP, and KATCo filed uncontested settlement agreements with FERC on January 18, 2023. Also on January 18, 2023, MP, PE and WP filed a motion for interim rates to implement certain aspects of the settled rate. The interim rates were approved by the FERC Chief Administrative Law Judge and took effect on January 1, 2023. As a result of the filed settlement, FirstEnergy recognized a $25 million pre-tax charge during the fourth quarter of 2022, which reflects the difference between amounts originally recorded as assets and amounts which will ultimately be recovered from customers as a result. On May 4, 2023, FERC issued an order approving the settlement agreement without condition or modification. Pursuant to the order, a compliance filing was filed on May 19, 2023, that implemented the terms of the settlement. On June 26, 2023, FERC issued a letter order approving the compliance filing.

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.

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

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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, have separately appealed and filed 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, which remains pending. Oral argument is scheduled for February 21, 2024.

Climate Change

In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris to reduce GHGs. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. On January 20, 2021, President Biden signed an executive order re-adopting the agreement on behalf of the U.S. 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 led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

FirstEnergy has pledged to achieve carbon neutrality by 2050 in GHGs within FirstEnergy’s direct operational control (Scope 1). With respect to our coal-fired plants in West Virginia, 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. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, 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 proposes stringent emissions limitations based on fuel type and unit retirement date. Comments on the proposed rule were submitted to the EPA on August 8, 2023. Depending on how final rules are ultimately implemented and 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.


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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. Public hearings on the proposed rules were held in April 2023 and comments were accepted through May 30, 2023. In the interim, the rule issued on August 31, 2020, remains in effect. 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 the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG 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 through the end of the first quarter of 2024, which request is pending technical review by the EPA. AE Supply continues to operate McElroy’s Run as a disposal facility for Pleasants Power Station, which is owned and operated by a non-affiliate.

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 the Consolidated Balance Sheets as of September 30, 2023, 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 $97 million have been accrued through December 31, 2023, of which, approximately $75 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 5 years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the DOJ’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. Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.

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. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the review, inquiries and investigations, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.

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. 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 former chairman of the PUCO, Samuel Randazzo, 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. No contingency has been reflected in FirstEnergy’s consolidated financial statements, as a loss is neither probable, nor is a loss or range of loss reasonably estimable.

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, which the Sixth Circuit granted on November 16, 2023. 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

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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. After a stay, pending final resolution of the United States v. Larry Householder, et al. criminal proceeding described above, the litigation has resumed pursuant to an order, dated March 15, 2023. Discovery is ongoing. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s section amended complaint, which the OAG opposed.

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.
•Miller v. Anderson, et al. (N.D. Ohio); 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); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the 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.

The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs. 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. If the S.D. Ohio’s final settlement approval is affirmed by the U.S. Court of Appeals for the Sixth Circuit, the settlement agreement is expected to resolve fully these shareholder derivative lawsuits.

On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022. On September 29, 2023, the N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit.

In letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that the Division was conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain all documents and information related to the same as such have been developed as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to

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FirstEnergy’s compliance programs. FE paid the civil penalty on January 4, 2023 and it will not be recovered from customers. The first annual compliance monitoring report was submitted in December 2023.

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 13, “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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES

FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements. Additional information regarding the application of accounting policies is included in the Notes to Consolidated Financial Statements.

Loss Contingencies

FirstEnergy is involved in a number of investigations, litigation, regulatory audits, arbitration, mediation, and similar proceedings, including those surrounding HB 6. FirstEnergy regularly assesses its liabilities and contingencies in connection with asserted or potential matters and establishes reserves when appropriate. In the preparation of the financial statements, FirstEnergy makes judgments regarding the future outcome of contingent events based on currently available information and accrues liabilities 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. Circumstances change over time and actual results may vary significantly from estimates. See Note 13, “Regulatory Matters” and Note 14, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements for additional information.

Revenue Recognition

The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from financial instruments, derivatives, late payment charges and other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the standard and accounted for under other existing GAAP guidance.

Contracts with Customers

FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of Regulated Distribution segment electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.

Regulated Transmission segment revenues are primarily derived from forward-looking formula rates. Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, 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. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.


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FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. See Note 2, "Revenue," of the Notes to Consolidated Financial Statements for additional information.

Regulatory Accounting

FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.

FirstEnergy reviews 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 include 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 or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next year's recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 13, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.

Pension and OPEB Accounting
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. FirstEnergy provides a modest amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy pension and OPEB obligations are based on various assumptions in calculating these amounts. These assumptions include discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates, mortality rates, among others. Actual results that differ from the assumptions and changes in assumptions are recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement and affect obligations.

Discount Rate - In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. FirstEnergy utilizes a full yield curve approach in the estimation of the service and interest components of net periodic benefit costs for pension and other postretirement benefits by applying specific spot rates along the full yield curve to the relevant projected cash flows.

Expected Return on Plan Assets - The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets, the historical performance of risk-based and fixed income securities and other factors. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. The expected return on pension and OPEB assets for 2024 is 8.0% and 7.0%, respectively.

Mortality Rates - The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. The Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due to the ongoing impact of COVID-19 was utilized to determine the 2024 benefit cost and obligation as of December 31, 2023, for FirstEnergy's pension and OPEB plans. The MP-2021 scale was published in 2021 by the Society of Actuaries.

Health Care Trend Rates - Included in determining trend rate assumptions are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates.

Net Periodic Benefit Costs (Credits) - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the 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 a remeasurement.

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The following table reflects the pre-tax portion of pension and OPEB costs that were charged (credited) to expense, including pension and OPEB mark-to-market adjustments and special termination benefits, in the three years ended December 31, 2023, 2022, and 2021:
Net Periodic Benefit Costs (Credits)202320222021
 (In millions)
Pension$57 $(389)$(582)
OPEB(40)(12)(170)
Total$17 $(401)$(752)
The annual pre-tax pension and OPEB mark-to-market adjustments, (gains) or losses, for the years ended December 31, 2023, 2022, and 2021 were $78 million, $(72) million and $(382) million, respectively.

FirstEnergy expects its 2024 pre-tax net periodic benefit credit including amounts capitalized (excluding mark-to-market adjustments) to be approximately $3 million based upon the following assumptions:

Assumption PensionOPEB
Effective rate for interest on benefit obligations4.92 %4.88 %
Effective rate for service costs5.17 %5.23 %
Effective rate for interest on service costs5.05 %5.16 %
Expected return on plan assets8.00 %7.00 %
Rate of compensation increase4.30 %N/A

The approximate effects on 2024 pension and OPEB net periodic benefit costs and the 2023 benefit obligation from changes in key assumptions are as follows:

Approximate Effect on 2024 Net Periodic Benefit Costs from Changes in Key Assumptions
Assumption ChangePensionOPEBTotal
  (In millions)
Discount rate
Change by 0.25%(1)
$230 $9 $239 
Expected return on plan assetsChange by 0.25%$17 $1 $18 
Health care trend rateChange by 1.0%N/A$6 $6 
(1)Assumes a parallel shift in yield curve.

Approximate Effect on December 31, 2023 Benefit Obligation from Changes in Key Assumptions
AssumptionChangePensionOPEBTotal
  (In millions)
Discount rate
Change by 0.25%(1)
$233 $9 $242 
Health care trend rateChange by 1.0%N/A$11 $11 
(1)Assumes a parallel shift in yield curve.

See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional information.

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Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes, reserve amounts for uncertain tax positions, and reporting of tax-related assets and liabilities such as the interpretation of tax laws and associated regulations. FirstEnergy is required to make judgments regarding the potential tax effects of various transactions and results of operations in order to estimate its obligations to taxing authorities.

Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

FirstEnergy accounts for uncertainty in income taxes in its financial statements using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. FirstEnergy recognizes interest expense or income related to uncertain tax positions by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, or new regulations or guidance, forecasted results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities.

See Note 7, "Taxes," of the Notes to Consolidated Financial Statements for additional information on income taxes.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements.
ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A relating to market risk is set forth in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial statements and supplementary data of FirstEnergy required in this item are set forth beginning on page 80.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of FirstEnergy Corp.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of FirstEnergy Corp. and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.


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Accounting for the Effects of Rate Regulation

As described in Note 1 to the consolidated financial statements, the Company’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Company is permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management reviews 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 include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. As of December 31, 2023, there were $369 million of regulatory assets and $1,214 million of regulatory liabilities.

The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the significant audit effort in assessing the impact of regulation on accounting for regulatory assets and liabilities and in evaluating the complex audit evidence related to whether the regulatory assets will be recovered and liabilities settled.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the accounting for regulatory matters, including controls over the evaluation of the recoverability and settlement of existing regulatory assets and liabilities. These procedures also included, among others, (i) obtaining the Company’s correspondence with regulators, (ii) evaluating the reasonableness of management’s assessment regarding regulatory guidance, proceedings, and legislation and the related accounting implications, and (iii) calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.


/s/ PricewaterhouseCoopers LLP
Cleveland, Ohio
February 13, 2024

We have served as the Company’s auditor since 2002.

 
 



79

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
(In millions, except per share amounts)202320222021
REVENUES:
Distribution services and retail generation $10,405 $9,916 $9,009 
Transmission2,049 1,863 1,608 
Other 416 680 515 
Total revenues(1)
12,870 12,459 11,132 
OPERATING EXPENSES:
Fuel538 730 481 
Purchased power4,108 3,863 2,964 
Other operating expenses3,594 3,817 3,196 
Provision for depreciation1,461 1,375 1,302 
Amortization (deferral) of regulatory assets, net(261)(365)269 
General taxes1,164 1,129 1,073 
DPA penalty (Note 14)
— — 230 
Gain on sale of Yards Creek — — (109)
Total operating expenses10,604 10,549 9,406 
OPERATING INCOME 2,266 1,910 1,726 
OTHER INCOME (EXPENSE):
Debt redemption costs (Note 11)
(36)(171)(2)
Equity method investment earnings (Note 1)175 168 31 
Miscellaneous income, net164 415 486 
Pension and OPEB mark-to-market adjustment(78)72 382 
Interest expense(1,124)(1,039)(1,139)
Capitalized financing costs97 84 75 
Total other expense(802)(471)(167)
INCOME BEFORE INCOME TAXES1,464 1,439 1,559 
INCOME TAXES 267 1,000 320 
INCOME FROM CONTINUING OPERATIONS1,197 439 1,239 
Discontinued operations (Note 16)(2)
(21)— 44 
NET INCOME$1,176 $439 $1,283 
Income attributable to noncontrolling interest (continuing operations)74 33 — 
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP.$1,102 $406 $1,283 
AMOUNTS ATTRIBUTABLE TO FIRSTENERGY CORP.
Earnings from continuing operations$1,123 $406 $1,239 
Earnings from discontinued operations(21)— 44 
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP.$1,102 $406 $1,283 
EARNINGS PER SHARE ATTRIBUTABLE TO FIRSTENERGY CORP. (Note 3)
Basic - continuing operations$1.96 $0.71 $2.27 
Basic - discontinued operations(0.04)— 0.08 
Basic$1.92 $0.71 $2.35 
Diluted - continuing operations$1.96 $0.71 $2.27 
Diluted - discontinued operations(0.04)— 0.08 
Diluted$1.92 $0.71 $2.35 
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic573 571 545 
Diluted574 572 546 
(1) Includes excise and gross receipts tax collections of $420 million, $406 million and $374 million in 2023, 2022 and 2021, respectively.
(2) Net of income tax benefit (expense) of ($21 million) and $48 million in 2023 and 2021, respectively.


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

80

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31,
(In millions)202320222021
NET INCOME$1,176 $439 $1,283 
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs(6)(9)(14)
Amortized losses on derivative hedges2 9 1 
Other comprehensive loss(4)— (13)
Income tax benefits on other comprehensive loss
(1)(1)(3)
Other comprehensive income (loss), net of tax(3)1 (10)
COMPREHENSIVE INCOME$1,173 $440 $1,273 
Comprehensive income attributable to noncontrolling interest74 33 — 
COMPREHENSIVE INCOME ATTRIBUTABLE TO FIRSTENERGY CORP.$1,099 $407 $1,273 








































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

81

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)December 31,
2023		December 31,
2022
ASSETS  
CURRENT ASSETS:  
Cash and cash equivalents$137 $160 
Restricted cash42 46 
Receivables-  
Customers1,382 1,455 
Less — Allowance for uncollectible customer receivables64 137 
1,318 1,318 
Other, net of allowance for uncollectible accounts of $15 in 2023 and $11 in 2022
266 253 
Materials and supplies, at average cost512 421 
Prepaid taxes and other293 217 
 2,568 2,415 
PROPERTY, PLANT AND EQUIPMENT:  
In service50,107 47,850 
Less — Accumulated provision for depreciation13,811 13,258 
 36,296 34,592 
Construction work in progress2,116 1,693 
 38,412 36,285 
INVESTMENTS AND OTHER NONCURRENT ASSETS:  
Goodwill5,618 5,618 
Investments (Note 10)
663 622 
Regulatory assets369 33 
Other1,137 1,135 
 7,787 7,408 
TOTAL ASSETS$48,767 $46,108 
LIABILITIES AND EQUITY  
CURRENT LIABILITIES:  
Currently payable long-term debt$1,250 $351 
Short-term borrowings775 100 
Accounts payable1,362 1,503 
Accrued interest292 254 
Accrued taxes700 668 
Accrued compensation and benefits304 272 
Dividends payable (Note 11)
235 223 
Customer deposits227 223 
Other241 364 
 5,386 3,958 
NONCURRENT LIABILITIES:
Long-term debt and other long-term obligations22,885 21,203 
Accumulated deferred income taxes4,530 4,202 
Retirement benefits1,663 2,335 
Regulatory liabilities1,214 1,847 
Other2,173 1,920 
32,465 31,507 
TOTAL LIABILITIES37,851 35,465 
EQUITY:  
Common stockholders' equity-  
Common stock, $0.10 par value, authorized 700,000,000 shares - 574,335,396 and 572,130,932 shares outstanding as of December 31, 2023 and 2022, respectively
57 57 
Other paid-in capital10,494 11,322 
Accumulated other comprehensive loss(17)(14)
Accumulated deficit(97)(1,199)
Total common stockholders' equity10,437 10,166 
Noncontrolling interest479 477 
TOTAL EQUITY10,916 10,643 
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 14)
TOTAL LIABILITIES AND EQUITY$48,767 $46,108 



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

82

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Common StockOther Paid-In CapitalAOCIAccumulated DeficitTotal Common Stockholders' Equity
(In millions)SharesAmountNCI Total Equity
Balance, January 1, 2021543 $54 $10,076 $(5)$(2,888)$7,237 $— $7,237 
Net income— — — — 1,283 1,283 — 1,283 
Other comprehensive loss, net of tax— — — (10)— (10)— (10)
Cash dividends declared on common stock(1)
— — (859)— — (859)— (859)
Common stock issuance (Note 11)
263971 — — 974 — 974 
Stock Investment Plan and share-based benefit plans1 — 50 — — 50 — 50 
Balance, December 31, 2021570 57 10,238 (15)(1,605)8,675 — 8,675 
Net income— — — — 406 406 33 439 
Other comprehensive income, net of tax — — — 1 — 1 — 1 
Cash dividends declared on common stock(1)
— — (892)— — (892)— (892)
Stock Investment Plan and share-based benefit plans2 — 98 — — 98 — 98 
FET minority interest sale, net of transaction costs (Note 1)— — 1,887 — — 1,887 451 2,338 
Distribution to FET minority interest— — — — — — (21)(21)
Capital contribution from FET minority interest— — — — — — 9 9 
Consolidated tax benefit allocation— — (5)— — (5)5 — 
Other— — (4)— — (4)— (4)
Balance, December 31, 2022572 57 11,322 (14)(1,199)10,166 477 10,643 
Net income— — — — 1,102 1,102 74 1,176 
Other comprehensive loss, net of tax— — — (3)— (3)— (3)
Cash dividends declared on common stock(2)
— — (917)— — (917)— (917)
Stock Investment Plan and share-based benefit plans2 — 89 — — 89 — 89 
Distribution to FET minority interest— — — — — — (72)(72)
Balance, December 31, 2023574 $57 $10,494 $(17)$(97)$10,437 $479 $10,916 
(1) Dividends declared for each share of common stock totaled $1.56 during 2022 and 2021.
(2) Dividends declared for each share of common stock totaled $1.60 during 2023.









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

83

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
(In millions)202320222021
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income$1,176 $439 $1,283 
Adjustments to reconcile net income to net cash from operating activities-
Depreciation, amortization and impairments1,280 1,317 1,664 
Employee benefit costs, net(9)(279)(300)
Pension and OPEB mark-to-market adjustments78 (72)(382)
Deferred income taxes and investment tax credits, net252 989 297 
Transmission revenue collections, net(180)79 182 
Gain on sale of Yards Creek— — (109)
Pension trust contribution(750)— — 
Loss (gain) on disposal, net of tax (Note 16)
21 — (47)
Changes in current assets and liabilities-
Receivables(13)(292)160 
Materials and supplies(91)(161)57 
Prepaid taxes and other current assets(43)(28)18 
Accounts payable(141)560 117 
Accrued taxes32 22 7 
Accrued interest38 (29)— 
Other current liabilities41 21 (52)
Cash collateral, net(218)111 31 
Employee benefit plan funding and related payments(50)(49)(48)
Other(36)55 (67)
Net cash provided from operating activities1,387 2,683 2,811 
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital investments(3,356)(2,848)(2,487)
Proceeds from sale of Yards Creek— — 155 
Sales of investment securities held in trusts38 48 48 
Purchases of investment securities held in trusts(50)(59)(59)
Asset removal costs(274)(213)(226)
Other(10)(4)10 
Net cash used for investing activities(3,652)(3,076)(2,559)
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt3,150 700 2,100 
Short-term borrowings, net675 100 — 
Common stock issuance— — 1,000 
Redemptions and repayments-
Long-term debt(537)(3,005)(532)
Short-term borrowings, net— — (2,200)
Proceeds from FET minority interest sale, net of transaction costs— 2,348 — 
Distributions to FET minority interest(72)(21)— 
Capital contributions from FET minority interest— 9 — 
Common stock dividend payments(906)(891)(849)
Other(72)(152)(61)
Net cash provided from (used for) financing activities2,238 (912)(542)
Net change in cash, cash equivalents and restricted cash(27)(1,305)(290)
Cash, cash equivalents, and restricted cash at beginning of period206 1,511 1,801 
Cash, cash equivalents, and restricted cash at end of period$179 $206 $1,511 
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid (received) during the year-
Interest (net of amounts capitalized) $1,002 $1,021 $1,085 
Income taxes, net of refunds $58 $21 $(7)
Significant non-cash transactions:
Accrued capital investments$252 $207 $114 
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

84

FIRSTENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note
Number
 
Page
Number
   
2Revenue
3Earnings Per Share
4Accumulated Other Comprehensive Income
5
6Stock-Based Compensation Plans
7Taxes
8Leases
9Variable Interest Entities
10Fair Value Measurements
11Capitalization
12Short-Term Borrowings and Bank Lines of Credit
13Regulatory Matters
14Commitments, Guarantees and Contingencies
15Segment Information
16Discontinued Operations

85

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2023: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, MP, AGC (a wholly owned subsidiary of MP), PE, WP and KATCo. Additionally, FET is a majority-owned subsidiary of FE, and is the parent company of ATSI, MAIT, PATH and TrAIL. In addition, FE 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, making FE PA a new, single operating entity. In addition to merging each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies, (i) WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and (ii) PN and ME contributed their respective Class B equity interests of MAIT to FE. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and serves an area with a population of approximately 4.5 million. FE PA operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.

On May 31, 2022, Brookfield and the Brookfield Guarantors acquired 19.9% of the issued and outstanding membership interests of FET. FirstEnergy presents the third-party investors’ ownership portion of FirstEnergy's net income, net assets and comprehensive income as NCI. NCI is included as a component of equity on the Consolidated Balance Sheets.

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, or costs that cannot be precisely identified 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 utility operating companies comprise one of the nation’s largest investor-owned electric systems, serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include more than 24,000 miles of transmission lines and two regional transmission operation centers. AGC and MP control 3,580 MWs of total capacity.

The accompanying consolidated financial statements have been prepared in accordance with GAAP and the rules and regulations of the SEC. 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 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.

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. As further discussed below, FE and its subsidiaries consolidate a VIE 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, including presenting long-term debt and other long-term obligations within “Noncurrent Liabilities” on the Consolidated Balance Sheets as compared to “Total Capitalization”.


86

Economic Conditions

Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending 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.

Facility Optimization

FirstEnergy has begun implementing its facility optimization plans, which focus on both cost savings and alignment with our flexible working arrangements and EESG priorities, which will result in exiting the General Office in Akron, Ohio, and other corporate facilities in Brecksville, Ohio, Greensburg, Pennsylvania and Morristown, New Jersey beginning in 2024. In December 2023, FirstEnergy purchased the General Office building with the intention to sell in the future. It is currently expected that the exit of the General Office and sale will 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.

Sale of Equity Interest in FirstEnergy Transmission, LLC

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 majority of the purchase price is expected to be paid in cash upon closing, and the remainder will be payable by the issuance of a promissory note, which is expected to be repaid by the end of 2024. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the PPUC. In addition, pursuant to the FET P&SA II, FirstEnergy made the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

Pursuant to the terms of the FET P&SA II, in connection with the closing, Brookfield, FET and FE will enter into the A&R FET LLC Agreement, which will amend and restate in its entirety the current 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, at the closing, the FET Board will consist of five directors, two appointed by Brookfield and three appointed by FE.

Reference Rate Reform

In March of 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): “Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (issued March 2020 and subsequently updated). This ASU, which introduces Topic ASC 848 to the FASB codification, provides temporary optional expedients and exceptions, that if elected, will ease the financial reporting burdens related to the market transition from London Inter-Bank Offered Rate and other interbank offered rates to alternative reference rates.

On April 27, 2023, FE, FET, the Utilities and the Transmission Companies entered into amendments to the 2021 Credit Facilities to, among other things: (i) permit the sale from FE to Brookfield of an incremental 30% equity interest in FET for a purchase price of $3.5 billion, (ii) permit the consolidation of the Pennsylvania Companies into a new, single operating entity, FE PA, which will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies, and (iii) transition the benchmark interest rate for borrowings under the 2021 Credit Facilities from London Inter-Bank Offered Rate to SOFR. During the second quarter of 2023, FirstEnergy utilized the optional expedient within ASC 848 to account for the amendments to the credit facilities as a continuation of the existing contract without additional analysis.
ACCOUNTING FOR THE EFFECTS OF REGULATION

FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.


87

FirstEnergy reviews 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 include 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 or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 13, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.

The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2023 and 2022, and the changes during the year 2023:
As of December 31,
Net Regulatory Assets (Liabilities) by Source20232022Change
 (In millions)
Customer payables for future income taxes$(2,382)$(2,463)$81 
Spent nuclear fuel disposal costs(83)(83)— 
Asset removal costs(652)(675)23 
Deferred transmission costs286 50 236 
Deferred generation costs572 235 337 
Deferred distribution costs247 164 83 
Storm-related costs799 683 116 
Energy efficiency program costs198 94 104 
New Jersey societal benefit costs79 94 (15)
Vegetation management102 63 39 
Other(11)24 (35)
Net Regulatory Liabilities included on the Consolidated Balance Sheets$(845)$(1,814)$969 

The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2023 and 2022, of which approximately $371 million and $511 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 aAs of December 31,
Current Return20232022Change
(In millions)
Deferred transmission costs$6 $8 $(2)
Deferred generation costs432 262 170 
Deferred distribution costs68 27 41 
Storm-related costs602 568 34 
Pandemic-related costs35 45 (10)
Vegetation management21 52 (31)
Other33 35 (2)
Regulatory Assets Not Earning a Current Return$1,197 $997 $200 
DERIVATIVES

FirstEnergy is exposed to limited financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.


88

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.
EQUITY METHOD INVESTMENTS
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 reflected in "Investments". 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 are assessed for impairment annually or whenever events and changes in circumstances indicate that the carrying amount of the investment may not be recoverable. If the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment.
Equity method investments included within "Investments" on the Consolidated Balance Sheets were $104 million and $90 million as of December 31, 2023 and 2022, respectively.
Global Holdings - 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 years ended December 31, 2023, 2022 and 2021, pre-tax income related to FEV’s ownership in Global Holding was $175 million, $168 million and $29 million, respectively. FEV’s pre-tax equity earnings and investment in Global Holding are included in Corporate/Other for segment reporting.
As of December 31, 2023 and 2022, the carrying value of the equity method investment was $66 million and $57 million, respectively. During 2023 and 2022, FEV received cash dividends from Global Holding totaling $165 million and $170 million, respectively, which were classified with “Cash from Operating Activities” on FirstEnergy’s Consolidated Statements of Cash Flow.
PATH WV - PATH, was 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 December 31, 2023 and 2022, the carrying value of the equity method investment was $17 million and $18 million, respectively. FirstEnergy's pre-tax equity earnings in PATH-WV were immaterial for the years ended December 31, 2023, 2022 and 2021.
GOODWILL

In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.

As of July 31, 2023, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment included: growth rates, interest rates, expected investments, utility sector market performance, regulatory and legal developments, and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary.

FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission. The following table presents goodwill by reporting unit as of December 31, 2023 and 2022:
(In millions)Regulated DistributionRegulated TransmissionConsolidated
Goodwill$5,004 $614 $5,618 


89

INVENTORY

Materials and supplies inventory primarily includes fuel inventory, emission allowances, and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials charged to inventory are at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory consists primarily of coal and reagents that are consumed at MP's generation plants, and is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed.

Emission allowances are accounted for as inventory at cost when purchased. FirstEnergy’s emission allowance compliance obligation, principally associated with MP's generation plant operations, is accrued to fuel expense at a weighted average cost based on each month’s emissions. When emission allowances are submitted to the EPA, inventory and the compliance obligation are reduced. Due to the ENEC, fuel, emission allowances and other fuel-related expenses have no material impact on current period earnings.

NONCONTROLLING INTEREST

FirstEnergy maintains a controlling financial interest in certain less than wholly owned subsidiaries. As a result, FirstEnergy presents the third-party investors’ ownership portion of FirstEnergy's net income, net assets and comprehensive income as noncontrolling interest. Noncontrolling interest is included as a component of equity on the Consolidated Balance Sheets.

On May 31, 2022, Brookfield and the Brookfield Guarantors acquired 19.9% of the issued and outstanding membership interests of FET. The difference between the cash consideration received, net of transaction costs of approximately $37 million, and the carrying value of the noncontrolling interest of $451 million was recorded as an increase to Other Paid-In Capital. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the transaction and remains in the Regulated Transmission segment.

Pursuant to the terms of the FET P&SA I, on May 31, 2022, Brookfield, FET and FE entered into the FET LLC Agreement. The 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 FET LLC Agreement, Brookfield is entitled to appoint a number of directors to the FET Board, in approximate proportion to Brookfield’s ownership percentage in FET (rounded to the next whole number). The FET Board now consists of five directors, one appointed by Brookfield and four appointed by FE.
PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and financing costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred.

Property, plant and equipment balances by segment as of December 31, 2023 and 2022, were as follows:
December 31, 2023
Property, Plant and Equipment
In Service(1)
Accum. Depr.(2)
Net PlantCWIPTotal
(In millions)
Regulated Distribution$33,453 $(10,039)$23,414 $860 $24,274 
Regulated Transmission15,538 (3,178)12,360 1,208 13,568 
Corporate/Other1,116 (594)522 48 570 
Total$50,107 $(13,811)$36,296 $2,116 $38,412 
December 31, 2022
Property, Plant and Equipment
In Service(1)
Accum. Depr.(2)
Net PlantCWIPTotal
(In millions)
Regulated Distribution$32,257 $(9,636)$22,621 $828 $23,449 
Regulated Transmission14,468 (2,978)11,490 818 12,308 
Corporate/Other1,125 (644)481 47 528 
Total$47,850 $(13,258)$34,592 $1,693 $36,285 
(1) Includes finance leases of $68 million and $105 million as of December 31, 2023 and 2022, respectively.
(2) Includes finance lease accumulated amortization of $33 million and $60 million as of December 31, 2023 and 2022, respectively.

Regulated Distribution has approximately $2.2 billion of total regulated generation property, plant and equipment as of December 31, 2023.

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FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were approximately 2.8% in 2023 and 2.7% in each of 2022 and 2021.

For the years ended December 31, 2023, 2022 and 2021, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $44 million, $56 million and $48 million, respectively, of allowance for equity funds used during construction and $53 million, $28 million and $27 million, respectively, of capitalized interest.

Asset Impairments

FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value.

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, considering 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. 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 cost, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.

The following table summarizes the changes to the ARO balances during 2023 and 2022:
ARO Reconciliation(In millions)
Balance, January 1, 2022$179 
Changes in timing and amount of estimated cash flows(2)
Liabilities settled (6)
Accretion14 
Balance, December 31, 2022$185 
Changes in timing and amount of estimated cash flows10 
Liabilities settled(2)
Accretion16 
Balance, December 31, 2023$209 

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 through the end of the first quarter of 2024, which request is pending technical review by the EPA. AE Supply continues to operate McElroy’s Run as a disposal facility for Pleasants Power Station, which is owned and operated by a non-affiliate.

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Jointly Owned Plants

AGC owns an undivided 16.25% interest (487 MWs) in the 3,003 MW Bath County pumped-storage, hydroelectric station in Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Total property, plant and equipment includes $145 million representing AGC's share in this facility as of December 31, 2023. AGC is obligated to pay its share of the costs of this jointly owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in operating expenses on FirstEnergy's Consolidated Statements of Income. AGC provides the generation capacity from this facility to its owner, MP, which is recovered from the ENEC.
NEW ACCOUNTING PRONOUNCEMENTS

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

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. For FirstEnergy, the guidance will be effective for fiscal years beginning after December 15, 2023 and interim periods within those fiscal years, with early adoption permitted.

ASU 2023-07, "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures " (Issued in November 2023): ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contain other disclosure requirements. Disclosure requirements within ASU 2023-07 include disclosing significant segment expenses by reportable segment if they are regularly provided to the CODM and included in each reported measure of segment profit or loss. Disclosures are required on both an annual and an interim basis. For FirstEnergy, the guidance will be effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.

ASU 2023-09, "Income taxes (Topic 280): Improvements to Income Tax Disclosures " (Issued in December 2023): ASU 2023-09 enhances disclosures primarily related to existing rate reconciliation and income taxes paid information to help investors better assess how a company’s operations and related tax risks and tax planning and operational opportunities affect the tax rate and prospects for future cash flows. For FirstEnergy, the guidance will be effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The amendments within ASU 2023-09 are to be applied on a prospective basis, with retrospective application permitted.
2. REVENUE

FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the standard and accounted for under other existing GAAP.

FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.

FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.

Regulated Distribution

The Regulated Distribution segment distributes electricity through FirstEnergy’s utility operating companies and also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 13, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.


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Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer.

Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and Incremental Auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur.

The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days.

ASC 606 excludes industry-specific accounting guidance for recognizing revenue from Alternative Revenue Programs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenues from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers.

Regulated Transmission

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are derived from primarily forward-looking formula rates. See Note 13, “Regulatory Matters,” for additional information.

Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, 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 rate base and actual costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.


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The following represents a disaggregation of revenue from contracts with customers for the years ended December 31, 2023, 2022 and 2021:
For the Years Ended December 31,
(In millions)202320222021
Regulated Distribution
Retail generation and distribution services(1)
Residential $6,583 $6,180 $5,713 
Commercial 2,600 2,499 2,284 
Industrial 1,298 1,338 1,091 
Street lighting/Other
105 85 75 
Wholesale 228 494362
Other revenue from contracts with customers(2)
113 104119
Total revenues from contracts with customers10,927 10,700 9,644 
Alternative Revenue Program(3)
— — (27)
Other revenue unrelated to contracts with customers(4)
111 10194
Total Regulated Distribution$11,038 $10,801 $9,711 
Regulated Transmission
ATSI $968 $912 $799 
TrAIL 279 270 233 
MAIT 395 340 288 
JCP&L 205 203 164 
MP, PE and WP 202 138124
Total revenues from contracts with customers2,049 1,863 1,608 
Other revenue unrelated to contracts with customers5 5 10 
Total Regulated Transmission $2,054 $1,868 $1,618 
Corporate/Other and Reconciling Adjustments(5)
Wholesale$11 $27 $14 
Retail generation and distribution services(5)
(181)(186)(154)
Other revenue unrelated to contracts with customers(5)
(52)(51)(57)
Total Corporate/Other and Reconciling $(222)$(210)$(197)
FirstEnergy Total Revenues $12,870 $12,459 $11,132 
(1) Includes approximately $58 million and $38 million as of December 31, 2022 and 2021, respectively, of customer refunds associated with the Ohio Stipulation that became effective in December 2021. See Note 13, “Regulatory Matters,” for further discussion.
(2) Primarily includes amounts collected from customers to administer and repay securitization bonds and pole attachment revenue.
(3) Reflects amount the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest.
(4) Primarily includes late payment charges and revenue from derivatives.
(5) Includes eliminations and reconciling adjustments of inter-segment revenues.


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RECEIVABLES
Receivables from contracts with customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Utilities. Billed and unbilled customer receivables as of December 31, 2023 and 2022, are included below.
As of December 31,
Customer Receivables20232022
 (In millions)
Billed(1)
$717 $674 
Unbilled665 781 
1,382 1,455 
Less: Uncollectible Reserve 64 137 
Total Customer Receivables $1,318 $1,318 
(1) Includes approximately $288 million and $290 million as of December 31, 2023 and 2022, respectively, that are past due by greater than 30 days.
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 Utilities are able to utilize to ensure payment. This analysis includes consideration of the outbreak of the pandemic and the impact on customer receivable balances outstanding and write-offs since the pandemic began and subsequent economic slowdown. 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.

During 2023, various regulatory actions, including extended installment plans, continue to impact the level of past due balances in certain states, resulting in the allowances for uncollectible customer receivables to remain elevated above 2019 pre-pandemic levels. However, normal collection activity has resumed, and arrears levels continue to decline towards pre-pandemic levels. As a result, FirstEnergy recognized a $77 million decrease to its allowance during 2023, of which $41 million was applied to existing deferred regulatory assets.
Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2023, 2022 and 2021 are as follows:
(In millions)202320222021
Customer Receivables:
Beginning of year balance $137 $159 $164 
Charged to income(1)
8 59 54 
Charged to other accounts(2)
34 62 42 
Write-offs (115)(143)(101)
End of year balance $64 $137 $159 
Other Receivables:
Beginning of year balance$11 $10 $26 
Charged to income 7 4 3 
Charged to other accounts(2)
(1)4 3 
Write-offs(2)(7)(22)
End of year balance$15 $11 $10 
(1) Customer receivable amounts charged to income for the years ended December 31, 2023, 2022, and 2021, include approximately $(15) million, $11 million, and $12 million, respectively, deferred for future recovery (refund).
(2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts.

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3. EARNINGS PER SHARE OF COMMON STOCK

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, as further discussed in Note 11, "Capitalization" under Long-term debt and other long-term obligations, is computed using the if-converted method.

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

For the Years Ended December 31,
Reconciliation of Basic and Diluted EPS of Common Stock202320222021
(In millions, except per share amounts)
Earnings Attributable to FE - continuing operations$1,123 $406 $1,239 
Earnings Attributable to FE - discontinued operations, net of tax(21)— 44 
Earnings Attributable to FE$1,102 $406 $1,283 
Share Count information:
Weighted average number of basic shares outstanding573 571 545 
Assumed exercise of dilutive share-based awards1 1 1 
Weighted average number of diluted shares outstanding574 572 546 
EPS Attributable to FE:
Income from continuing operations, basic$1.96 $0.71 $2.27 
Discontinued operations, basic (0.04)— 0.08 
Basic EPS$1.92 $0.71 $2.35 
Income from continuing operations, diluted$1.96 $0.71 $2.27 
Discontinued operations, diluted(0.04)— 0.08 
Diluted EPS$1.92 $0.71 $2.35 

For the years ended December 31, 2023, 2022 and 2021, there was no material amount of shares excluded from the calculation of diluted shares outstanding, as their inclusion would be 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 year ended December 31, 2023, 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. See Note 11, "Capitalization" for additional details on the 2026 Convertible Notes that were issued during the second quarter of 2023.

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4. ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI for the years ended December 31, 2023, 2022 and 2021, for FirstEnergy are shown in the following table:
202320222021
(In millions)
Gains & Losses on Cash Flow Hedges(1)
AOCI Balance, January 1,$— $(7)$(8)
Amounts reclassified from AOCI2 9 1 
Income tax on other comprehensive income— 2 — 
Other comprehensive income, net of tax2 7 1 
AOCI Balance, December 31,$2 $— $(7)
Defined Benefit Pension & OPEB Plans(2)(3)
AOCI Balance, January 1,$(14)$(8)$3 
Amounts reclassified from AOCI(6)(9)(14)
Income tax benefits on other comprehensive loss(1)(3)(3)
Other comprehensive loss, net of tax(5)(6)(11)
AOCI Balance, December 31,$(19)$(14)$(8)
Total FirstEnergy Corp. AOCI
AOCI Balance, January 1,$(14)$(15)$(5)
Other comprehensive income (loss), net of tax(3)1 (10)
AOCI Balance, December 31,$(17)$(14)$(15)
(1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. Amounts reclassified from AOCI affects Interest expense line item in Consolidated Statements of Income.
(2) Amortization of prior service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Postemployment Benefits," for additional details.
(3) Income tax (benefits) on other comprehensive income (loss) affects Income taxes line item in Consolidated Statements of Income.
5. PENSION AND OTHER POSTEMPLOYMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

On May 9, 2023, FirstEnergy announced a voluntary retirement program for eligible non-bargaining employees, known as the PEER. More than 65% of eligible employees, totaling approximately 450 employees, accepted the PEER, which included lump sum compensation equivalent to severance benefits, healthcare continuation costs and a temporary pension enhancement. Most PEER participating employees departed in 2023. The temporary pension enhancement and healthcare continuation costs are classified as special termination costs within net periodic benefit costs (credits). In addition to the PEER, FirstEnergy notified and involuntarily separated approximately 90 employees on May 9, 2023. Management expects the cost savings resulting from these initiatives to support FirstEnergy’s growth plans.

FirstEnergy’s pension funding policy is based on actuarial computations using the projected unit credit method. On May 12, 2023, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan. 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.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care
trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans or whenever a plan is determined to qualify for a remeasurement. The fair value of the plan assets represents the actual market value as of the measurement date.
Actuarial Assumptions PensionOPEB
2023(2)
20222021
2023(2)
20222021
Assumptions Related to Benefit Obligations:
Discount rate5.05 %5.23 %3.02 %4.97 %5.16 %2.84 %
Rate of compensation increase4.30 %4.30 %4.10 %N/AN/AN/A
Cash balance weighted average interest crediting rate4.94 %4.04 %2.57 %N/AN/AN/A
Assumptions Related to Benefit Costs:(1)
Effective rate for interest on benefit obligations
5.10% / 4.80%
2.44 %1.94 %5.06 %2.18 %1.66 %
Effective rate for service costs
5.34% / 5.11%
3.28 %3.10 %5.41 %3.41 %3.03 %
Effective rate for interest on service costs
5.22% / 4.94%
2.96 %2.58 %5.33 %3.24 %2.83 %
Expected return on plan assets8.00 %7.50 %7.50 %7.00 %7.50 %7.50 %
Rate of compensation increase4.30 %4.10 %4.10 %N/AN/AN/A
Assumed Health Care Cost Trend Rates:
Health care cost trend rate assumed (pre/post-Medicare)N/AN/AN/A
7.00%-
6.50%
6.00%-
5.50%

5.75%-
5.25%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)N/AN/AN/A4.50 %4.50 %4.50 %
Year that the rate reaches the ultimate trend rateN/AN/AN/A203320292028
(1) Excludes impact of pension and OPEB mark-to-market adjustments.
(2) As a result of the interim plan remeasurement during 2023, there were different rates in effect from January 1, 2023, through April 30, 2023 compared to May 1, 2023 through December 31, 2023.
Discount Rate - In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. 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.

Expected Return on Plan Assets - The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets, the historical performance of risk-based and fixed income securities and other factors. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement.

Pension and OPEB Returns202320222021
 Actual gains or (losses) on plan assets - $ millions$751 $(1,830)$689 
Actual gains or (losses) on plan assets - %11.2 %(19.1)%7.9 %
Expected return on plan assets - $ millions$601 $696 $688 
Expected return on plan assets - %
8.00% for pension

7.00% for OPEB
7.50 %7.50 %

Mortality Rates - During 2023, the Society of Actuaries elected not to release a new mortality improvement scale due to data available being severely impacted by COVID-19. It was determined that the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due to the ongoing impact of COVID-19 was most appropriate and such was utilized to determine the obligation as of December 31, 2023, for the FirstEnergy pension and OPEB plans. This adjustment acknowledges COVID-19 cannot be eradicated and assumes reductions in other causes will not offset future COVID-19 deaths enough to produce a normal level of improvements.

Net Periodic Benefit Costs (Credits) - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the 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 a remeasurement. 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.
Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31,PensionOPEB
202320222021202320222021
 (In millions)
Service cost(1)
$139 $184 $195 $2 $3 $4 
Interest cost 428 273 226 21 11 11 
Expected return on plan assets (570)(657)(652)(31)(39)(36)
Amortization of prior service costs (credits)2 2 3 (8)(11)(17)
Special termination benefits(2)
21 — — 8 — — 
Pension & OPEB mark-to-market108 (98)(253)(30)26 (129)
Net periodic benefit costs (credits)$128 $(296)$(481)$(38)$(10)$(167)
(1) Includes amounts capitalized.
(2) Related to benefits provided in connection with the PEER.

For the years ended December 31, 2023, 2022 and 2021, approximately $36 million, $15 million and $(31) million, respectively, of the annual pension and OPEB mark-to-market charges (credits) were allocated to the Regulated Transmission companies under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates.

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. FirstEnergy elected the practical expedient to remeasure pension plan assets and obligations as of April 30, 2023, which is the month-end closest to the date of the voluntary contribution. The pension mark-to-market adjustment primarily reflects higher than expected return on assets, partially offset by a 29 basis points decrease in the discount rate used to measure benefit obligations.

In the fourth quarter of 2023, FirstEnergy recognized a $137 million pension and OPEB mark-to-market adjustment loss, primarily reflecting lower than expected return on assets, partially offset by an 11 basis points increase in the discount rate used to measure pension benefit obligations from May 1, 2023, and the gain associated with the pension lift-out, as described below.

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 FES and FENOC 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 will continue to evaluate other lift-outs in the future based on market and other conditions.
PensionOPEB
Obligations/Funded Status - Qualified and Non-Qualified Plans2023202220232022
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1$8,828 $11,479$439 $549
Service cost139 1842 3
Interest cost428 27321 11
Plan participants’ contributions— —4 3
Special termination benefits21 —8 —
Medicare retiree drug subsidy— —— 1
Lift-out transaction (719)—— —
Actuarial loss (gain)256 (2,515)8 (83)
Benefits paid(590)(593)(41)(45)
Benefit obligation as of December 31$8,363 $8,828$441 $439
Change in fair value of plan assets:
Fair value of plan assets as of January 1$6,693 $9,020$460 $548
Actual return on plan assets682 (1,760)69 (70)
Lift-out transaction (683)—— —
Company contributions777 2624 24
Plan participants’ contributions— —4 3
Benefits paid(590)(593)(41)(45)
Fair value of plan assets as of December 31$6,879 $6,693$516 $460
Funded Status:
Qualified plan$(1,090)$(1,734)$— $—
Non-qualified plans(394)(401)— —
Funded Status (Net liability as of December 31)$(1,484)$(2,135)$75 $21
Accumulated benefit obligation$7,324 $8,500 $— $— 
Amounts Recognized in AOCI:
Prior service cost (credit)$4 $6 $(1)$(10)
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2023 and 2022.
December 31, 2023Asset Allocation
Level 1Level 2Level 3Total
(In millions)
Cash and short-term securities$— $755 $— $755 11 %
Public equity1,811 4 — 1,815 26 %
Fixed income— 1,784 — 1,784 26 %
Derivatives2 37 — 39 — %
Total(1)
$1,813 $2,580 $— $4,393 63 %
Private - equity and debt funds(2)
1,296 19 %
Insurance-linked securities(2)
107 2 %
Hedge funds(2)
410 6 %
Real estate funds(2)
721 10 %
Total Investments$6,927 100 %
(1) Excludes $(48) million as of December 31, 2023, of receivables, payables, taxes, cash collateral for derivatives and accrued income associated with financial instruments reflected within the fair value table.
(2) NAV used as a practical expedient to approximate fair value.

December 31, 2022Asset Allocation
Level 1Level 2Level 3Total
(In millions)
Cash and short-term securities$— $714 $— $714 11 %
Public equity1,871 216 — 2,087 33 %
Fixed income— 942 — 942 15 %
Derivatives(38)2 — (36)(1)%
Total(1)
$1,833 $1,874 $— $3,707 58 %
Private - equity and debt funds(2)
1,061 17 %
Insurance-linked securities(2)
159 3 %
Hedge funds(2)
563 9 %
Real estate funds(2)
853 13 %
Total Investments$6,343 100 %
(1) Excludes $350 million as of December 31, 2022, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
(2) NAV used as a practical expedient to approximate fair value.

Private – equity and debt funds: Private equity and private debt funds primarily include limited partnerships that invest in equity or directly originated senior loans of high-quality middle market operating companies. Distributions are received periodically through the liquidation of underlying assets in each fund. For most private equity and debt funds, immediate access to capital at the limited partner’s discretion is not available and such funds prevent full redemption and return of capital until fund liquidation. The purpose of each fund is to maximize total return of capital with an emphasis on minimizing default risk. Each fund’s NAV is made available to fund participants quarterly.

Insurance Linked Securities funds: The insurance linked securities funds invest in securities which indirectly participate in portfolios of reinsurance and retrocession contracts which primarily cover catastrophe property risks. Redemptions can be achieved with 90-day notices with gating factors that may apply. The purpose of these investments is to generate attractive risk-adjusted returns that are demonstrably uncorrelated with traditional asset classes. Each fund’s NAV is made available to fund participants monthly.

Hedge funds: The hedge funds invest in a combination of long and short equity, multi-strategy, global macro and structured credit strategies. Redemptions can be achieved with 90-day notices with gating factors that may apply. The purpose of these investments is to deliver diversified risk-adjusted returns to traditional asset classes. Each fund’s NAV is made available to fund participants monthly.

Real estate funds: The real estate funds primarily invest in U.S commercial real estate markets that include office, residential, retail, industrial, life science/lab space, storage and student housing. The investment values of the real estate properties are determined on a quarterly basis by independent market appraisers hired by the board of directors of each fund. Distributions from each fund will be received as the underlying investments of the fund are liquidated. Each investor’s ability to withdraw capital from certain funds may be limited depending on whether a queue has been established. The purpose of each fund is to invest in real estate and real estate related assets that generate a total return from current income and capital appreciation which exceeds the applicable fund’s index. Each fund’s NAV is made available to fund participants quarterly.

As of December 31, 2023, and 2022, the OPEB trust investments measured at fair value were as follows:
December 31, 2023Asset Allocation
Level 1Level 2Level 3Total
(In millions)
Cash and short-term securities$— $100 $— $100 19 %
Public equity258 — — 258 50 %
Fixed income— 158 — 158 31 %
Total$258 $258 $— $516 100 %


December 31, 2022Asset Allocation
Level 1Level 2Level 3Total
(In millions)
Cash and short-term securities$— $87 $— $87 19 %
Public equity217 — — 217 47 %
Fixed income:— 157 — 157 34 %
Total(1)
$217 $244 $— $461 100 %
(1) Excludes $(1) million as of December 31, 2022, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2023 were as follows:
Target Asset Allocations
Pension OPEB
Equities30 %50 %
Fixed income28.5 %50 %
Alternative investments 5 %— %
Real estate10 %— %
Private - equity and debt funds20 %— %
Cash and derivatives 6.5 %— %
100 %100 %
FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contribution.
OPEB
PensionBenefit PaymentsSubsidy Receipts
(In millions)
2024$554 $49 $(1)
2025562 41 (1)
2026564 40 — 
2027569 39 — 
2028571 37 — 
Years 2029-20332,877 164 (2)
6. STOCK-BASED COMPENSATION PLANS

FirstEnergy grants stock-based awards through the ICP 2020, primarily in the form of restricted stock and performance-based restricted stock units. No shares are available for future grants or issuance under ICP 2015.

The ICP 2020 and ICP 2015 include shareholder authorization to each issue 10 million shares of common stock or their equivalent. Shares not issued due to forfeitures or cancellations originally granted through the ICP 2015 may be added back to the ICP 2020. As of December 31, 2023, approximately 10.1 million shares were available for future grants under the ICP 2020 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. Shares granted under the ICP 2020 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from less

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than a year, primarily due to the issuance of prorated awards to newly hired executives, to four years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) savings plan and DCPD.

Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur.

FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2023, 2022 and 2021, were $6 million, $8 million and $10 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited.

Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2023, 2022 and 2021, are included in the following tables:
For the Years Ended December 31,
Stock-based Compensation Plan202320222021
(In millions)
Restricted stock units $39 $55 $40 
Restricted stock5 3 2 
401(k) savings plan38 36 35 
EDCP & DCPD1 7 13 
   Total $83 $101 $90 
Stock-based compensation costs, net of amounts capitalized$44 $54 $43 

Income tax benefits associated with stock-based compensation plan expense were $6 million, $8 million and $5 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Restricted Stock Units

Two-thirds of each performance-based restricted stock unit award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair market value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Restricted stock units include a performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method. Beginning with awards granted in 2022, restricted stock units include a relative total shareholder return as a performance metric, weighted at 35%, utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is also calculated using the Monte Carlo simulation method. In addition, outstanding awards are subject to an absolute total shareholder return, if FirstEnergy's total shareholder return is negative for the three-year cumulative performance period, restricted stock unit awards will be capped at a payout of 100%.

Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2023, was $22 million. During 2023, approximately $6 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2023.

The vesting period for the performance-based restricted stock unit awards granted in 2023, 2022 and 2021, were each three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award.


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Restricted stock unit activity for the year ended December 31, 2023, was as follows:
Restricted Stock Unit Activity
Shares
(in millions)
Weighted-Average Grant Date Fair Value (per share)
Nonvested as of January 1, 20231.9 $41.57 
Granted in 20231.4 38.36 
Forfeited in 2023(0.2)39.32 
Vested in 2023(1)
(0.6)39.38 
Nonvested as of December 31, 20232.5 $38.82 
(1) Excludes dividend equivalents of approximately 63 thousand shares earned during vesting period.

The weighted-average fair value per share of awards granted in 2023, 2022 and 2021 was $38.36, $41.49 and $35.50 per share, respectively. For the years ended December 31, 2023, 2022, and 2021, the fair value of restricted stock units vested was $24 million, $26 million, and $34 million, respectively. As of December 31, 2023, there was approximately $32 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years.

Restricted Stock

Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended 2023, was as follows:
Restricted Stock Activity
Shares
(in millions)
Weighted-Average Grant Date Fair Value (per share)
Nonvested as of January 1, 20230.20 $42.35 
Granted in 20230.30 37.42 
Forfeited in 2023(0.02)36.86 
Vested in 2023(0.02)39.45 
Nonvested as of December 31, 20230.46 $39.57 
The weighted average vesting period for restricted stock granted in 2023 was 2.4 years. As of December 31, 2023, there was $11 million of total unrecognized compensation cost related to non-vested restricted stock, which is expected to be recognized over a period of approximately four years.

401(k) Savings Plan

In each of 2023 and 2022, approximately 1 million shares of FE common stock, respectively, were issued and contributed to employee participants' accounts.

EDCP

Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts, where they are tracked as units. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividend equivalents are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. Awards deferred into a retirement stock account will pay out in cash upon separation, including retirement, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash as a lump sum or over a defined period of time period as elected by the participant. The liability recognized for EDCP of approximately $175 million and $193 million as of December 31, 2023 and 2022, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets.

DCPD

Under the DCPD, members of the FE Board can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $4 million and $8 million as of December 31, 2023 and 2022, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets.

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7. TAXES
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities.

On August 16, 2022, President Biden signed into law the IRA of 2022, which, 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 net operating losses 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 it will be subject to the AMT beginning in 2023. Accordingly, FirstEnergy made a first quarter estimated payment of AMT of approximately $49 million in April 2023. In June 2023, the U.S. Treasury issued additional guidance that eliminated the requirement of corporations to include AMT in quarterly estimated tax payments, pending further guidance on the application and administration of AMT. Therefore, as a result of guidance issued to date, the current forecast of AMT obligation, and the amount of AMT already paid in April 2023, FirstEnergy did not make any additional AMT payments for the 2023 tax year. Until final U.S. Treasury regulations are issued, the amount of AMT FirstEnergy pays could be significantly different than current estimates or it may not be a payer at all. 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 discussed above, FirstEnergy expects to close on the sale of an additional 30% interest in FET in 2024, at which time FirstEnergy expects to realize an approximate $7.5 billion tax gain from the combined sale of 49.9% of the membership interests of FET for consideration received and recapture of negative tax basis in FET. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards, as further discussed below, which will be used to offset a majority of the tax gain from the FET sale and expected taxable income in 2024, however due to certain limitations on utilization enacted in the Tax Act, a portion of the NOL will carry into 2025 and possibly beyond. As a result of the expected additional 30% sale in FET, FirstEnergy recognized a charge to income tax expense in the fourth quarter of 2022 of approximately $752 million, representing the deferred tax liability associated with the deferred tax gain on the initial 19.9% sale of FET that closed in May 2022, such deferred gain consisting of consideration received on the sale and the recapture of estimated negative tax basis in FET impacted by taxable income and loss among other factors. In the fourth quarter of 2023, FirstEnergy recognized a charge to income tax expense of approximately $58 million as a true-up of the deferred tax liability associated with the deferred tax gain.

During the third quarter of 2023, FirstEnergy recognized a tax benefit of approximately $65 million, net of a reserve for uncertain tax positions, from the reduction of state income taxes and partial release of a valuation allowance for the expected utilization of state NOL based on an assessment of regulated business operations and a change in the composition of a state tax return filing group.

In the fourth quarter of 2023, FirstEnergy recognized a tax benefit of approximately $37 million from the remeasurement of valuation allowance previously recorded on business interest expense carryforwards, net of carryforward adjustments, based on the expectation that FirstEnergy will be able to utilize these tax benefits on realized and future earnings and distributions from FirstEnergy’s interests in FET and FEV. The business interest expense could not be deducted previously due to certain limitations imposed on interest expense from non-utility operations under section 163(j) of the Tax Act, however, the Tax Act provides that the nondeductible interest can be carried forward indefinitely and deducted against income from non-utility operations. During 2022, FirstEnergy recognized an approximate $38 million tax benefit from remeasurement of the prior valuation allowance on interest expense carryforwards.

On March 29, 2023, the West Virginia Governor signed into law House Bill 3286, which provides corporate taxpayers a reduction to pre-apportionment federal taxable income with the amount necessary to offset the increase in the net deferred tax liability (or decrease in the net deferred tax asset) caused by West Virginia’s apportionment law change enacted in 2021. Beginning with the 2033 tax year, qualifying taxpayers can subtract one-tenth of the amount each year for ten years. Taxpayers intending to claim this subtraction will have to file a statement with the West Virginia tax commissioner by July 1, 2024, specifying the total amount of subtraction to be claimed. Accordingly, FirstEnergy recorded a state deferred tax asset of approximately $9 million in the first quarter of 2023, which was fully reserved. In conjunction with the assessment of regulated business operations discussed above, FirstEnergy removed the $9 million reserve and reduced the state deferred tax asset to approximately $4 million, and recorded a corresponding $4 million regulatory liability associated with the amount expected to be refunded to customers in future rates.

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The following table provides the composite of income taxes on income from continuing operations for the years ended 2023, 2022 and 2021:

INCOME TAXES ON INCOME FROM CONTINUING OPERATIONSFor the Years Ended December 31,
202320222021
(In millions)
Currently payable -
Federal(1)
$14 $— $2 
State1 11 21 
15 11 23 
Deferred, net -   
Federal(2)
279 946 174 
State(24)47 127 
255 993 301 
Investment tax credit amortization(3)(4)(4)
Total income taxes on income from continuing operations$267 $1,000 $320 
(1) Excludes $2 million of federal tax benefit associated with discontinued operations for the year ended December 31, 2021.
(2) Excludes $21 million of federal tax expense and $46 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2023 and 2021, respectively.

FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period but are not consistent from period to period. The following table provides a reconciliation of federal income tax expense at the federal statutory rate to the total income taxes on income from continuing operations for the years ended December 31, 2023, 2022 and 2021:
For the Years Ended December 31,
202320222021
(In millions)
Income from continuing operations, before income taxes$1,464 $1,439 $1,559 
Federal income tax expense at the 21% statutory rate $307 $302 $327 
Increases (reductions) in taxes resulting from-
State and municipal income taxes, net of federal tax benefit80 56 122 
AFUDC equity and other flow-through(30)(26)(29)
Amortization of investment tax credits(3)(4)(4)
Deferred gain on 19.9% FET minority interest sale
58 752 — 
Federal tax credits claimed (3)(3)(34)
Nondeductible DPA monetary penalty
— — 52 
Excess deferred tax amortization due to the Tax Act(46)(51)(54)
Uncertain tax positions41 2 (82)
Valuation allowances(146)(47)17 
Other, net9 19 5 
Total income taxes on income from continuing operations$267 $1,000 $320 
Effective income tax rate (continuing operations)18.2 %69.5 %20.5 %
Accumulated deferred income taxes as of December 31, 2023 and 2022, are as follows:

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As of December 31,
20232022
(In millions)
Property basis differences$5,787 $5,528 
Pension and OPEB(331)(496)
Regulatory asset/liability647 432 
Deferred compensation(153)(149)
Deferred gain on 19.9% FET minority interest sale
810 752 
Loss carryforwards and tax credits(2,192)(2,073)
Valuation reserve226 440 
Other(264)(232)
Net accumulated deferred income tax liability$4,530 $4,202 

FirstEnergy has recorded as deferred income tax assets the effect of federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2023, FirstEnergy's loss carryforwards primarily consisted of $8.1 billion ($1.7 billion, net of tax) of federal NOL carryforwards, $5.9 billion ($1.2 billion, net of tax) of which have no expiration and the remainder that will begin to expire in 2031. As discussed above, FirstEnergy expects to utilize the majority of its federal NOL carryforwards by the end of 2024. However, due to certain limitations on utilization enacted in the Tax Act, a portion of the NOL will carry into 2025 and possibly beyond. In addition, FirstEnergy's tax credit carryforwards primarily consisted of AMT credits of $57 million, which have no expiration, and federal general business tax credits of $12 million that begin to expire in 2039.

The table below summarizes pre-tax NOL carryforwards and their respective anticipated expirations for state and local income tax purposes of approximately $13.5 billion ($436 million, net of tax) for FirstEnergy, of which approximately $6.1 billion ($233 million, net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions.
Expiration PeriodStateLocal
(In millions)
2024-2028$2,403 $5,269 
2029-20331,415 — 
2034-20381,079 — 
2039-2043823 — 
Indefinite2,469 — 
$8,189 $5,269 

The following table summarizes the changes in valuation allowances on federal, state, and local deferred tax assets related to business interest expense carryforwards and employee compensation deduction limitations under section 162(m), in addition to state and local NOLs discussed above for the years ended December 31, 2023, 2022 and 2021:

(In millions)202320222021
Beginning of year balance$440 $484 $496 
Charged to income(214)(44)(12)
Charged to other accounts— — — 
Write-offs— — — 
End of year balance$226 $440 $484 

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. If ultimately recognized in future years, all of the unrecognized income tax benefits would impact the effective tax rate.


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The following table summarizes the changes (gross) in uncertain tax positions for the years ended December 31, 2023, 2022 and 2021:
(In millions)
Balance, January 1, 2021$139 
Current year increases15 
Prior year decreases(8)
Effectively settled with taxing authorities
(97)
        Decrease for lapse in statute
(2)
Balance, December 31, 2021$47 
Prior year increases2 
        Decrease for lapse in statute
(7)
Balance, December 31, 2022$42 
Prior years increases88 
Effectively settled with taxing authorities
(24)
        Decrease for lapse in statute
(1)
Balance, December 31, 2023$105 

As of December 31, 2023, none of the unrecognized tax benefits are expected to be resolved during 2024 as a result of settlements with taxing authorities or the statute of limitations expiring.

FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes interest expense or income and penalties in the provision for income taxes. Due to uncertain tax positions that were effectively settled with tax authorities during 2023, approximately $9 million in net interest was reversed. There was no material interest expense or income, or penalties, related to uncertain tax positions in 2022 and 2021.

General Taxes

General tax expense for the years ended December 31, 2023, 2022 and 2021, recognized in continuing operations is summarized as follows:
For the Years Ended December 31,
202320222021
(In millions)
kWh excise$185 $191 $189 
State gross receipts235 219 190 
Real and personal property615 596 571 
Social security and unemployment113 105 103 
Other16 18 20 
Total general taxes$1,164 $1,129 $1,073 
8. LEASES

FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.

FirstEnergy accounts for leases under, "Leases (Topic 842)". Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. In December 2023, FirstEnergy purchased the General Office building in Akron, Ohio with the intention to sell in the future. It is currently expected that the exit of the General Office and sale will occur in 2025. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. FirstEnergy has elected a policy to not separate lease components from non-lease components for all asset classes.


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For vehicles leased under certain master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, FirstEnergy is committed to pay the difference in the actual fair value and the residual value guarantee. FirstEnergy does not believe it is probable that it will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly.

Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense recorded for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:
For the Year Ended December 31, 2023
(In millions)VehiclesBuildingsOtherTotal
Operating lease costs(1)
$60 $5 $14 $79 
Finance lease costs:
Amortization of right-of-use assets 4 2 2 8 
Interest on lease liabilities — 5 — 5 
Total finance lease cost4 7 2 13 
Total lease cost $64 $12 $16 $92 
(1) Includes $27 million of short-term lease costs.

For the Year Ended December 31, 2022
(In millions)VehiclesBuildingsOtherTotal
Operating lease costs(1)
$50 $8 $15 $73 
Finance lease costs:
Amortization of right-of-use assets 10 1 2 13 
Interest on lease liabilities — 3 — 3 
Total finance lease cost10 4 2 16 
Total lease cost $60 $12 $17 $89 
(1) Includes $19 million of short-term lease costs.

For the Year Ended December 31, 2021
(In millions)VehiclesBuildingsOtherTotal
Operating lease costs(1)
$44 $9 $18 $71 
Finance lease costs:
Amortization of right-of-use assets 12 1 1 14 
Interest on lease liabilities 1 3 — 4 
Total finance lease cost13 4 1 18 
Total lease cost $57 $13 $19 $89 
(1) Includes $21 million of short-term lease costs.

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Supplemental cash flow information related to leases was as follows:
For the Years Ended December 31,
(In millions)202320222021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$54 $56 $64 
Operating cash flows from finance leases3 34
Finance cash flows from finance leases8 1213
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $13 $26 $60 
Finance leases — — 5 

Lease terms and discount rates were as follows:
As of December 31,
202320222021
Weighted-average remaining lease terms (years)
Operating leases 5.937.307.97
Finance leases 12.2611.338.12
Weighted-average discount rate(1)
Operating leases 4.51 %4.22 %4.16 %
Finance leases 14.73 %14.77 %12.22 %
(1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.

Supplemental balance sheet information related to leases was as follows:
As of December 31,
(In millions)Financial Statement Line Item20232022
Assets
Operating lease(1)
Deferred charges and other assets$205 $262 
Finance lease(2)
Property, plant and equipment35 45 
Total leased assets $240 $307 
Liabilities
Current:
Operating Other current liabilities$47 $48 
Finance Currently payable long-term debt3 6 
Noncurrent:
Operating Other noncurrent liabilities179 247 
Finance Long-term debt and other long-term obligations11 17 
Total leased liabilities $240 $318 
(1) Operating lease assets are recorded net of accumulated amortization of $139 million and $114 million as of December 31, 2023 and 2022, respectively.
(2) Finance lease assets are recorded net of accumulated amortization of $33 million and $60 million as of December 31, 2023 and 2022, respectively.

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Maturities of lease liabilities as of December 31, 2023, were as follows:
(In millions)Operating LeasesFinance LeasesTotal
2024$54 $4 $58 
202547 4 51 
202643 4 47 
202737 3 40 
202833 4 37 
Thereafter 47 — 47 
Total lease payments(1)
261 19 280 
Less imputed interest 35 5 40 
Total net present value$226 $14 $240 
(1) Operating lease payments for certain leases are offset by sublease receipts of $8 million over 9 years.

As of December 31, 2023, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $42 million. These leases are expected to commence within the next 18 months with lease terms of 5 to 10 years.    
9. VARIABLE INTEREST ENTITIES

FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (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 $11,024 million and $10,104 million of consolidated VIE assets, as of December 31, 2023 and 2022, respectively, that can only be used to settle the liabilities of the applicable VIE. Total liabilities include approximately $7,835 million and $7,573 million as of December 31, 2023 and 2022, 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 utility. As of December 31, 2023 and 2022, $191 million and $206 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 December 31, 2023 and 2022, $218 million and $247 million of environmental control bonds were outstanding, respectively.


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Restricted cash included on the FE Consolidated Balance Sheets of $40 million and $41 million as of December 31, 2023 and 2022 respectively, relates to cash collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies.

FET

FET is a holding company that owns equity interests in ATSI, MAIT, TrAIL and PATH. As of December 31, 2023, FE has ownership in FET of 80.1% with Brookfield having 19.9%. 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 will bring FE’s equity ownership in FET to 50.1% and Brookfield to 49.9%. The FET Minority Equity Interest Sale is expected to close by the end of first quarter of 2024. FirstEnergy has concluded that FET is a VIE and that FE is the primarily 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 will be granted incremental consent rights upon closing of the incremental 30% 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 and FET 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 December 31, 2023 and 2022. 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 December 31,
2023		December 31,
2022
Cash and cash equivalents$76 $77 
Receivables8879 
Materials and supplies, at average cost1 1 
Prepaid taxes and other23 23 
Total current assets 188 180 
Property, plant and equipment, net10,227 9,365 
Goodwill224 224 
Investments 19 20 
Regulatory assets16 1 
Other310 273 
Total noncurrent assets 10,796 9,883 
TOTAL ASSETS$10,984 $10,063 


LiabilitiesDecember 31,
2023		December 31,
2022
Accounts payable2 — 
Accrued interest63 58 
Accrued taxes262 278 
Other14 7 
Total current liabilities 341 343 
Long-term debt and other long-term obligations5,275 4,949 
Accumulated deferred income taxes1,218 1,129 
Regulatory liabilities307 443 
Other285 256 
Total noncurrent liabilities 7,085 6,777 
TOTAL LIABILITIES$7,426 $7,120 



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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 NUG entities at its Regulated Distribution segment 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 December 31, 2023, FirstEnergy maintains four long-term PPAs with NUG 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.

During 2023, FirstEnergy terminated the PPA with the NUG entity in which it had previously applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers.
10. 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 December 31, 2023, from those used as of December 31, 2022. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty 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.

For investments reported at NAV where there is no readily determinable fair value, a practical expedient is available that allows the NAV to approximate fair value. Investments that use NAV as a practical expedient are excluded from the requirement to be categorized within the fair value hierarchy tables. Instead, these investments are reported outside of the fair value hierarchy tables to assist in the reconciliation of investment balances reported in the tables to the balance sheet. FirstEnergy has elected the NAV practical expedient for investments in private equity funds, insurance-linked securities, hedge funds (absolute return) and real estate funds held within the pension plan. See Note 5, "Pension And Other Postemployment Benefits" for the pension financial assets accounted for at fair value by level within the fair value hierarchy.

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The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:
December 31, 2023December 31, 2022
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets(In millions)
Derivative assets FTRs(1)
$— $— $4 $4 $— $— $11 $11 
Equity securities2 — — 2 2 — — 2 
U.S. state debt securities— 275 — 275 — 266 — 266 
Cash, cash equivalents and restricted cash(2)
179 — — 179 206 — — 206 
Other(3)
— 40 — 40 — 40 — 40 
Total assets$181 $315 $4 $500 $208 $306 $11 $525 
Liabilities
Derivative liabilities FTRs(1)
$— $— $(1)$(1)$— $— $(2)$(2)
Total liabilities$— $— $(1)$(1)$— $— $(2)$(2)
Net assets (liabilities)$181 $315 $3 $499 $208 $306 $9 $523 
(1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.
(2) Restricted cash of $42 million and $46 million as of December 31, 2023 and 2022, respectively, primarily relates to cash collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies. See Note 11, Capitalization for additional information.
(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 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 JCP&L spent nuclear fuel disposal trusts 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 nuclear fuel disposal trusts as of December 31, 2023 and 2022:
December 31, 2023(1)
December 31, 2022(2)
Cost BasisUnrealized GainsUnrealized LossesFair ValueCost BasisUnrealized GainsUnrealized LossesFair Value
(In millions)
Debt securities$301 $1 $(27)$275 $294 $— $(28)$266 
(1) Excludes short-term cash investments of $6 million.
(2) Excludes short-term cash investments of $5 million.


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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 years ended December 31, 2023, 2022 and 2021, were as follows:
For the Years Ended December 31,
202320222021
(In millions)
Sale Proceeds$38 $48 $48 
Realized Gains— 8 — 
Realized Losses(3)(13)(3)
Interest and Dividend Income12 11 11 


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 and equity method investments are reflected in the “Miscellaneous Income, net” line of FirstEnergy’s Consolidated Statements of Income. Other investments were $382 million and $351 million as of December 31, 2023 and 2022, 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 years ended December 31, 2023, 2022 and 2021, pre-tax income (expense) related to corporate-owned life insurance policies were $18 million, $(20) million and $13 million, respectively. 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 December 31, 2023 and 2022:
As of December 31,
 20232022
(In millions)
Carrying Value$24,254 $21,641 
Fair Value23,003 19,784 

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 December 31, 2023 and 2022.

See Note 11, "Capitalization," for further information on long-term debt issued and redeemed during the twelve months ended December 31, 2023.
11. CAPITALIZATION
COMMON STOCK

Retained Earnings and Dividends

As of December 31, 2023, FirstEnergy had an accumulated deficit of $97 million. Dividends declared in 2023 totaled $1.60 per share and dividends declared in 2022 totaled $1.56 per share. Dividends of $0.39 per share were declared in the first, second, third and fourth quarters in 2022 and the first and second quarters in 2023. In September 2023, the FE Board declared a $0.02 per share increase to the quarterly common dividend payable December 1, 2023, to $0.41 per share, which represents a 5% increase compared to the quarterly payments of $0.39 per share paid by FE since March 2020. The dividend declared in the fourth quarter of 2023, payable on March 1, 2024, was also $0.41 per share.


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The amount and timing of all dividend declarations are subject to the discretion of the FE Board and its consideration of business conditions, results of operations, financial condition, risks and uncertainties of the government investigations, and other factors.

When FE makes distributions to shareholders, it is required to subsequently determine and report the tax characterization of those distributions for purposes of shareholders’ income taxes. Whether a distribution is characterized as a dividend or a return of capital (and possible capital gain) depends upon an internal tax calculation to determine earnings and profits for income tax purposes. Earnings and profits should not be confused with earnings or net income under GAAP. Further, after FE reports the expected tax characterization of distributions it has paid, the actual characterization could vary from its expectation with the result that holders of FE's common stock could incur different income tax liabilities than expected.

In general, distributions are characterized as dividends to the extent the amount of such distributions do not exceed FE's calculation of current or accumulated earnings and profits. Distributions in excess of current and accumulated earnings and profits may be treated as a non-taxable return of capital. Generally, a non-taxable return of capital will reduce an investor’s basis in FirstEnergy's stock for federal tax purposes, which will impact the calculation of gain or loss when the stock is sold.

Provided the FET Minority Equity Interest Sale closes as anticipated, FE expects to realize an over $7 billion tax gain in 2024. This tax gain is estimated to create sufficient earnings and profits to cause distributions made during 2024 to be characterized as ordinary dividends for federal income tax purposes. Upon such characterization, shareholders are urged to consult their own tax advisors regarding the income tax treatment of FE's distributions to them.

In addition to paying dividends from retained earnings, the Ohio Companies and JCP&L have authorization from FERC to pay cash dividends to FE from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent, MP, from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The articles of incorporation, indentures, regulatory limitations, FET P&SA I and FET P&SA II, and various other agreements, including those relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2023.

Common Stock Issuance

FE issued approximately 2 million shares of common stock in 2023, 2 million shares of common stock in 2022 and 1 million shares of common stock in 2021 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans.

On November 6, 2021, FE entered into a Common Stock Purchase Agreement with BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., for the private placement of 25,588,535 shares of FE common stock, par value $0.10 per share, at a price of $39.08 per share, representing an investment of $1.0 billion. The transaction settled on December 13, 2021. Issuance costs associated with the transaction were approximately $26 million as of December 31, 2021.


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PREFERRED AND PREFERENCE STOCK

FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2023, as follows:
Preferred StockPreference Stock
Shares AuthorizedPar ValueShares AuthorizedPar Value
FE5,000,000 $100   
OE6,000,000 $100 8,000,000 no par
OE8,000,000 $25   
Penn(1)
1,200,000 $100   
CEI4,000,000 no par3,000,000 no par
TE3,000,000 $100 5,000,000 $25 
TE12,000,000 $25 
JCP&L15,600,000 no par
ME(1)
10,000,000 no par
PN(1)
11,435,000 no par
MP940,000 $100 
PE10,000,000 $0.01 
WP(1)
32,000,000 no par
(1) On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity. FE PA has not been authorized to issue preferred stock or preference stock.

As of December 31, 2023 and 2022, there were no preferred stock or preference stock outstanding.

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2023 and 2022:

As of December 31, 2023As of December 31,
Maturity DateInterest Rate20232022
(In millions)
FMBs and secured notes - fixed rate2024-2059
2.650% - 8.250%
$5,709 $5,153 
Unsecured notes - fixed rate2024-2050
1.600% - 7.375%
18,545 16,488 
Finance lease obligations14 23 
Unamortized debt discounts(9)(5)
Unamortized debt issuance costs(127)(110)
Unamortized fair value adjustments3 5 
Currently payable long-term debt(1,250)(351)
Total long-term debt and other long-term obligations$22,885 $21,203 

See Note 8, "Leases," for additional information related to finance leases.


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FirstEnergy had the following redemptions and issuances during the twelve months ended December 31, 2023:

CompanyTypeRedemption/Issuance DateInterest RateMaturityAmount
(In millions)		Description
Redemptions(1)
MEUnsecured NotesMarch, 20233.50%2023$300ME redeemed unsecured notes that became due.
FEUnsecured NotesMay, 20237.38%2031$194
FE repurchased approximately $194 million of the principal amount of its 2031 Notes through the open market for $228 million including a premium of approximately $34 million ($27 million after-tax). In addition, FE recognized approximately $2 million ($1 million after-tax) of deferred cash flow hedge losses associated with the FE debt redemptions.
Issuances
WPFMBsJanuary, 20235.29%2033$50Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MAITUnsecured NotesFebruary, 20235.39%2033$175Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MEUnsecured NotesMarch, 20235.20%2028$425
Proceeds were used to repay short-term borrowings, including borrowings incurred to repay, at maturity, the $300 million aggregate principal amount of ME's 3.50% unsecured notes due March 15, 2023, to finance capital expenditures and for other general corporate purposes.
PNUnsecured NotesMarch, 20235.15%2026$300Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
ATSIUnsecured NotesMay, 20235.13%2033$150Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
FEUnsecured Convertible NotesMay, 20234.00%2026$1,500
Proceeds were used to repay short-term borrowings, to repurchase a portion of its 2031 Notes, to fund the qualified pension plan and for other general corporate purposes.
PEFMBsSeptember, 20235.64%2028$100Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
PEFMBsSeptember, 20235.73%2030$50Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MPFMBsSeptember, 20235.85%2034$400
Proceeds are to be used for repaying short-term and long-term debt, including MP’s $400 million 4.10% FMBs due April 15, 2024, to finance capital expenditures and for other general corporate purposes.
(1) Excludes principal payments on securitized bonds.

Convertible Notes

As discussed above, on May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, with a fixed interest rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. However, FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date. The 2026 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $1.48 billion, net of issuance costs.

Prior to the close of business on the business day immediately preceding February 1, 2026, the 2026 Convertible Notes will be convertible at the option of the holders only under the following conditions:

•During any calendar quarter, if the last reported sale price of FE’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;
•During the five consecutive business day period immediately after any 10 consecutive trading day period in which the trading price per $1,000 principal amount of the 2026 Convertible Notes for each trading day of such 10 trading day period was less than 98% of the product of the last reported sale price of FE’s common stock and the conversion rate on each such trading day; or
•Upon the occurrence of certain corporate events specified in the indenture governing the 2026 Convertible Notes.

On and after February 1, 2026, until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2026 Convertible Notes may convert all or any portion of their 2026 Convertible Notes at their option at any time at the conversion rate then in effect, irrespective of these conditions. FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash up to the aggregate principal amount of the 2026 Convertible Notes being converted and by paying cash or delivering shares of FE’s common stock (or a combination of each), at its election, of its conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted.

The conversion rate for the 2026 Convertible Notes will initially be 21.3620 shares of FE’s common stock per $1,000 principal amount of the 2026 Convertible Notes (equivalent to an initial conversion price of approximately $46.81 per share of FE’s

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common stock). The initial conversion price of the 2026 Convertible Notes represents a premium of approximately 20% over the last reported sale price of FE’s common stock on the New York Stock Exchange on May 1, 2023. The conversion rate and the corresponding conversion price will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.

If FE undergoes a fundamental change (as defined in the relevant indenture), subject to certain conditions, holders of the 2026 Convertible Notes may require FE to repurchase for cash all or any portion of their 2026 Convertible Notes at a repurchase price equal to 100% of the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date (as defined in the relevant indenture). In addition, if certain fundamental changes occur, FE may be required, in certain circumstances, to increase the conversion rate for any 2026 Convertible Notes converted in connection with such fundamental changes by a specified number of shares of its common stock.

The following table presents scheduled debt repayments or debt that has been noticed for redemption for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2023.

(In millions)20242025202620272028
Scheduled debt repayments $1,246$2,023$2,876$2,003$2,453

Securitized Bonds

Environmental Control Bonds

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 December 31, 2023 and 2022, $218 million and $247 million of environmental control bonds were outstanding, respectively.

Phase-In Recovery Bonds

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 utility. As of December 31, 2023 and 2022, $191 million and $206 million of the phase-in recovery bonds were outstanding, respectively.

FMBs

The Ohio Companies, Penn, MP, PE, and WP each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. The outstanding debt under the FMBs of specific FE PA predecessors (WP and Penn) were assumed by FE PA.

Debt Covenant Default Provisions

FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2023, FirstEnergy remains in compliance with all debt covenant provisions.

Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it, or any of its significant subsidiaries, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Such defaults by any of the Utilities or Transmission Companies would cross-default certain FE financing arrangements containing these provisions, and a certain FET Financing arrangement, with respect to the Transmission Companies only. Such defaults by AE Supply would not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or its subsidiaries.

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12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

FirstEnergy had $775 million and $100 million of outstanding short-term borrowings as of December 31, 2023 and 2022, respectively.

On October 18, 2021, FE, FET, the Utilities, and the Transmission Companies 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. KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 2024.

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;
•Transmission Companies, $850 million revolving credit facility; and
•KATCo, $150 million revolving credit facility.

As of December 31, 2023, available liquidity under the 2021 and 2023 Credit Facilities was approximately $5.0 billion.

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 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.

Subject to each borrower’s sublimit, certain amounts 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 December 31, 2023, FirstEnergy had $4 million in outstanding LOCs.

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 December 31, 2023, 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.


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FirstEnergy Money Pools

FirstEnergy’s utility 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. 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 RatesRegulated Companies’ Money PoolUnregulated Companies’ Money Pool
2023202220232022
For the Years Ended December 31, 6.30 %2.27 %6.01 %2.14 %

Weighted Average Interest Rates

The annual weighted average interest rates on short-term borrowings outstanding as of December 31, 2023 and 2022, were 6.96% and 3.93%, respectively.

13. REGULATORY MATTERS

STATE REGULATION

Each of the Utilities' 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.

The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2023:
CompanyRates Effective For CustomersAllowed Debt/EquityAllowed ROE
CEIMay 2009
51% /49%
10.5%
ME(1)
January 2017
48.8% / 51.2%
Settled(2)
MPFebruary 2015
54% / 46%
Settled(2)
JCP&LNovember 2021
48.6% / 51.4%
9.6%
OEJanuary 2009
51% /49%
10.5%
PE (West Virginia)February 2015
51% / 49%
Settled(2)
PE (Maryland)October 2023
47% / 53%
9.5%
PN(1)
January 2017
47.4% /52.6%
Settled(2)
Penn(1)
January 2017
49.9% / 50.1%
Settled(2)
TEJanuary 2009
51% / 49%
10.5%
WP(1)
January 2017
49.7% / 50.3%
Settled(2)
(1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. Additionally, on January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity, and will operate under the rate districts of the former Pennsylvania Companies.
(2) Commission-approved settlement agreements did not disclose ROE rates.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of October 19, 2023. 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.

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On March 22, 2023, PE filed a base rate case with the MDPSC, utilizing a test year based on twelve months of actual 2022 data. The base rate case request included an annual increase in base distribution rates of $50.4 million, 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. The rate case additionally requested approval to continue an EDIS to fund three service reliability and resiliency programs, two new proposed programs to assist low-income customers and cost recovery of certain expenses associated with PE’s pilot electric vehicle charger program and its COVID-19 pandemic response. On October 18, 2023, the MDPSC approved an annual increase in base distribution rates of $28 million, effective October 19, 2023. The order denied PE’s request to establish a pension/OPEB regulatory asset (or liability), allowed recovery of most COVID-19 deferred costs; and rejected the continuation of PE’s EDIS, as PE's reliability has improved such that the surcharge recovery mechanism is no longer merited at this time. The MDPSC also ordered an independent audit of certain allocations from FESC to PE and denied recovery of approximately $12 million in rate base associated with certain corporate support costs recorded to capital accounts resulting from the FERC Audit. On January 3, 2024, the MDPSC issued an order granting PE’s request for reconsideration and increased PE’s allowed distribution rates by another $0.7 million.

The EmPOWER Maryland program requires 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. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance. 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. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Consistent with a December 29, 2022, order by the MDPSC phasing out the ability of Maryland utilities to earn a return on EmPOWER investments, PE will be required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025 and 100% in 2026. Notwithstanding the order to phase out PE’s ability to earn a return on its EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and 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 amortized balances was extended through the end of 2031. Additionally at the direction of the MDPSC, PE together with other Maryland utilities are 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 $310 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 $310 million scenario for most programs, with some modifications.

On April 17, 2023, PE submitted a proposal to the MDPSC seeking approval to end its PPA with the Warrior Run generating station. The PPA for Warrior Run was a requirement of the Public Utility Regulatory Policies Act of 1978. PE’s Maryland customers currently pay a surcharge on their electric bill in connection with the Warrior Run PPA, which fluctuates from year to year based on the difference between what PE pays for the output of the plant and what PE is able to recover by reselling that output into PJM. PE negotiated a termination of the PPA, which the MDPSC approved on June 21, 2023, and became effective June 28, 2023, requiring it to pay Warrior Run a fixed amount of $51 million annually through 2029, for a total of $357 million. During the second quarter of 2023, a liability was established for the $357 million termination fee, of which $55 million was included in “Other current liabilities” and $302 million in “Other non-current liabilities”, and as the cost of the termination fee will be recovered through the current surcharge, an offsetting regulatory asset was established on FirstEnergy’s Consolidated Balance Sheets, and results in no impact to FirstEnergy’s or PE’s current or future earnings and is expected to result in savings for PE’s Maryland customers. On July 26, 2023, the MDPSC approved the change in surcharge, effective August 1, 2023, after previously approving the termination of the agreement.

NEW JERSEY

JCP&L operates under NJBPU approved rates that took effect as of January 1, 2021, and were effective for customers as of November 1, 2021. 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.

On March 16, 2023, JCP&L filed a base rate case with the NJBPU, utilizing a test year based on six months of actual data for the second half of calendar year 2022, and six months of forecasted data for the first half of calendar year 2023. The rate case requested an annual net increase in base distribution revenues of approximately $185 million, 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 2023 expense) and the actual annual amount each year using the delayed recognition method. JCP&L updated its base rate case in filings made on June 2, 2023 and August 7, 2023 to provide actual test-year data for the twelve months ended June 30, 2023, and update its proposed annual net increase in base rate distribution revenues to approximately $192 million. In addition to the above, JCP&L’s request includes, among other things, approval of two new proposed programs to assist low-income customers, cost recovery of certain investments and expenses associated with its electric vehicle and AMI programs, an update of its depreciation rates, modifications to its storm cost recovery, and tariff modifications to update standard construction costs. A procedural schedule was adopted with evidentiary hearings to be held the week of January 8, 2024. On October 17, 2023, JCP&L requested a suspension of the procedural schedule to enter into

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formal settlement discussions, which all parties agreed, and the administrative law judge granted the same day. On February 2, 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 provides for an $85 million annual base distribution revenues increase for JCP&L, which, if approved by the NJBPU, is expected to take effect February 15, 2024, and be effective for customers on June 1, 2024. Until those new rates become effective for customers, JCP&L would begin to amortize 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 will begin no later than March 1, 2024 and represents an approximate investment of $95 million. JCP&L expects to amend its pending EnergizeNJ petition upon receipt of NJBPU approval of the base rate case settlement, to include the second phase of its reliability improvement plan that is expected to address any remaining high-priority circuits not addressed in the first phase. The settlement did not include the request 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 the delayed recognition method, however, JCP&L has the ability to pursue in a future separate proceeding.

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 December 5, 2023, JCP&L filed a petition with the NJBPU for a six-month extension of EE&C Plan I, which was originally scheduled to end on June 30, 2024, but would end on December 31, 2024, with the extension. The proposed budget for the extension period would add approximately $69 million to the original program cost. Under the proposal, JCP&L would 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.

On March 6, 2023, the NJBPU issued final rules modifying its regulations to reflect its CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate 100% of CTA savings to customers; and (iii) exclude transmission assets of EDCs in the savings calculation. The final rules of practice were applied by JCP&L in its most recent base rate case filing described above.

On October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for distribution base rate increase. The settlement provided for a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which became effective for customers on November 1, 2021. The settlement additionally provided 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 filed its comments on July 31, 2023. The parties have filed responses.

On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 and continuing until the New Jersey Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. No moratorium on residential disconnections remains in effect for investor-owned electric utilities such as JCP&L. Legislation was enacted on March 25, 2022, prohibiting utilities from disconnecting electric service to customers that have applied for utility bill assistance before June 15, 2022 until such time as the state agency administering the assistance program makes a decision on the application and further requiring that all utilities offer a deferred payment arrangement meeting certain minimum criteria after the state agency’s decision on the application has been made. On July 17, 2023, JCP&L submitted a stand-alone filing to recover approximately $31 million, through October 1, 2023, in incremental costs and interest incurred during the COVID-19 pandemic.

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

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JCP&L’s control. FERC staff subsequently requested additional information on JCP&L’s application, which JCP&L provided. 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 MW. 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 anticipates submitting the second part of its two-part application in the first quarter of 2024.

On November 9, 2023, JCP&L filed a petition for approval of its second 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 costs of EnergizeNJ would be recovered through JCP&L's base rates via annual and semi-annual base rate adjustment filings. Public hearings have been requested but are not yet scheduled. JCP&L has requested that the NJBPU issue a final decision and order no later than May 22, 2024, based on a June 1, 2024, commencement date for EnergizeNJ. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from the NJBPU of the base rate case stipulation that was filed on February 2, 2024.

OHIO

The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies currently operate under ESP IV, effective June 1, 2016 and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 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 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. ESP V proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, with process enhancements designed to reduce costs to customers. ESP V also proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual revenue cap increases of $15 to $21 million per year, based on reliability performance, and Rider AMI for recovery of approved grid modernization investments. ESP V proposes new riders to support continued maintenance of the distribution system, including vegetation management and storm restoration operating expense. In addition, ESP V proposes four-year energy efficiency and peak demand reduction programs for residential and commercial customers, with cost recovery spread over eight years. ESP V further includes a commitment to spend $52 million in total over the eight-year term, without recovery from customers, on initiatives to assist low-income customers, education and incentives to help ensure customers have good experiences with electric vehicles. Hearings commenced on November 7, 2023 and concluded on December 6, 2023. On December 6, 2023, certain intervenors filed a motion requesting a limited stay of the Ohio Companies’ proposal to continue Rider DCR. The Ohio Companies contested the motion, which is pending.

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. This matter remains 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. Hearings are scheduled to commence on April 16, 2024. On January 22, 2024, OCC filed a motion requesting a stay of phase two. The Ohio Companies contested the motion, which is pending.


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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.

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 Rider DCR 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.

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.

In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR 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 Rider DCR 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.

On August 16, 2022, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6- related matters for a period of six months, which request was granted by the PUCO on August 24, 2022. On February 22, 2023, the U.S. Attorney for the Southern District of Ohio again requested that the PUCO stay the above pending HB-6 related matters for a period of six months, which request was granted by the PUCO on March 8, 2023. On August 10, 2023, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6-related matters for a period of six additional months, which was approved by the PUCO on August 23, 2023. On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order, 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 ESP V as well as Grid Mod I and Grid Mod II along with the investigations. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing. The four cases remain stayed in their entirety, including discovery and motions, and all related procedural schedules are vacated.

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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.

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. This matter remains pending before the PUCO.

See Note 14, "Commitments, Guarantees and Contingencies" below for additional details on the government investigations and subsequent 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 continue the current rate structure of ME, PN, Penn, and WP until the earlier of 2033 or in the fourth base rate case 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 to 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 June 25, 2021, the Pennsylvania Office of Consumer Advocate filed a complaint against Penn’s quarterly DSIC rate, disputing the recoverability of the Companies’ automated distribution management system investment under the DSIC mechanism. On January 26, 2022, the parties filed a joint petition for settlement that resolves all issues in this matter, which was approved by the PPUC without modification on April 14, 2022.

Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates. The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for accumulated deferred income taxes and state taxes. The PPUC issued the order as directed.

On March 6, 2023, FirstEnergy filed applications with the PPUC, NYPSC and FERC seeking approval to consolidate the Pennsylvania Companies into a new, single operating entity. The PA Consolidation includes, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the contribution of Class B equity interests of MAIT then held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale as further described above), (c) the formation of FE PA and (d) the merger of each of the Pennsylvania Companies with and into FE PA, with FE PA surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. On August 30, 2023, the parties filed a settlement agreement recommending that the PPUC approve the PA Consolidation subject to the terms of the settlement, which include among other things, $650 thousand over five years in bill assistance for income-eligible customers and the Pennsylvania Companies’ commitment to (i) not seek full distribution rate unification until the earlier of 10 years or in the fourth base rate case filed after January 1, 2025 and (ii) track and share with customers certain operational and administrative efficiency costs associated with the PA Consolidation. The PPUC, NYPSC and FERC approved FirstEnergy’s applications on December 7, 2023, November 16, 2023, and August 14, 2023, respectively. The transaction closed on January 1, 2024 making FE PA FirstEnergy's only regulated utility in Pennsylvania.

On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Minority 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 Minority Equity Interest Sale. On November 24, 2023,

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CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority that it has 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 include among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement is currently pending PPUC approval.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective in February 2015. 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 updated annually.

On August 25, 2022, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $183.8 million beginning January 1, 2023, which represents a 12.2% increase to the rates then in effect. The increase was driven by an under recovery during the review period (July 1, 2021, to June 30, 2022) of approximately $145 million due to higher coal, reagent, and emission allowance expenses. This filing additionally addresses, among other things, the WVPSC’s May 2022 request for a prudence review of current rates. At a hearing on December 8, 2022, the parties in the case presented a unanimous settlement to increase rates by approximately $92 million, effective January 1, 2023, and carry over to MP and PE’s 2023 ENEC case, approximately $92 million at a carrying charge of 4%. In an order dated December 30, 2022, the WVPSC approved the settlement with respect to the proposed rate increase, but MP and PE rates remain subject to a prudence review in their 2023 ENEC case. The order also instructed MP to evaluate the feasibility of purchasing the 1,300 MW Pleasants Power Station and file a summary of the evaluation, which MP and PE filed on March 31, 2023. MP and PE provided the WVPSC with regular status reports throughout the second quarter of 2023 regarding the process of their evaluation. Subsequently, the owner of Pleasants entered into an agreement to sell Pleasants to an indirect wholly owned subsidiary of Omnis Global Technologies, LLC, which transaction closed on August 1, 2023. As a result, MP and PE ceased consideration of the possible purchase of Pleasants and on August 30, 2023, the WVPSC closed the proceeding.

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 represents 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 provides for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $255 million to be recovered through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover more than $50 million than the 2024 ENEC balance and a party elects to invoke a case filing. An order is expected by March 2024.

On November 22, 2021, MP and PE filed with the WVPSC their plan to construct 50 MWs of solar generation at five sites in West Virginia. The plan includes a tariff to offer solar power to West Virginia customers and cost recovery for MP and PE through a surcharge for any solar investment not fully subscribed by their customers. A hearing was held in mid-March 2022 and on April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, the requested tariff and requiring MP and PE to subscribe at least 85% of the planned 50 MWs before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. On April 24, 2023, MP and PE sought final tariff approval from the WVPSC for three of the five solar sites, representing 30 MWs of generation, and requested approval of a surcharge to recover any costs above the final approved tariff. 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 are 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 is expected in the first quarter 2024.

On March 2, 2023, the WVPSC ordered an audit of MP and PE focused on: (i) the lobbying and promotional/image building expenses, including those related to HB 6, incurred by MP and PE from 2018 to 2022 (ii) intra-corporate charges, (iii) the accounting for charges included in the ENEC cost recovery accounts of MP and PE during the same time period, and (iv) review and report on the findings, including those specific to MP and PE, set forth in the FERC Audit described below as well as a review and report of the responses by MP and PE thereto. The audit began in September 2023 and concluded with a filing of the report on December 28, 2023. The audit found no evidence that HB 6 related costs were included in the 2022 test year, and no errors or omission were identified that would materially affect lobbying and image building costs or expenses charged to the

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ENEC for the period 2018 to 2022. Additionally, there were several recommended adjustments and recommendations, however, none are expected to have a material effect on FirstEnergy, MP or PE. The report was evaluated as part of the ongoing base rate case.

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 includes the approximate $76 million requested in a depreciation case filed on January 13, 2023 and described more fully above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. New rates are expected to be effective by the end of March 2024. On January 23, 2024, MP, PE and various parties filed with a joint settlement agreement with the WVPSC, which recommends a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense. Additionally, the settlement includes 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 recover (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. An order is expected by the end of the first quarter of 2024 with new rates to be effective March 27, 2024.

On August 31, 2023, MP and PE filed its biennial review of their vegetation management program and surcharge. MP and PE have proposed an approximate $17 million increase in the surcharge rates, due to an under recovery in the prior two-year period and increased forecast costs. The case was unanimously settled by the parties on November 29, 2023, approved by the WVPSC on January 8, 2024, and the $17 million increase proposed by MP and PE went into effect on January 1, 2024. See Note 14, “Commitments, Guarantees and Contingencies - Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.

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 Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP 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.

The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2023:
CompanyRates EffectiveCapital StructureAllowed ROE
ATSIJanuary 2015Actual (13-month average)10.38%
JCP&L
January 2020Actual (13-month average)10.20%
MPJanuary 2021
Lower of Actual (13-month average) or 56%
10.45%
PE January 2021
Lower of Actual (13-month average) or 56%
10.45%
WP(1)
January 2021
Lower of Actual (13-month average) or 56%
10.45%
MAITJuly 2017
Lower of Actual (13-month average) or 60%
10.3%
TrAILJuly 2008Actual (year-end)
12.7%(2) / 11.7%(3)
(1) On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo
(2) TrAIL the Line and Black Oak Static Var Compensator
(3) All other projects


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 Utilities 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 Utilities 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 Utilities, 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 $13 million of costs have been recovered as of December 31, 2023. 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 distribution utilities 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 $310 million of certain corporate support costs allocated to distribution capital assets. 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. FirstEnergy is actively participating in the appeal 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

On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. FirstEnergy submitted comments through the Edison Electric Institute and as part of a consortium of PJM Transmission Owners. In a supplemental rulemaking proceeding that was initiated on April 15, 2021, FERC requested comments on, among other things, whether to require utilities that have been members of an RTO for three years or more and

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that have been collecting an “RTO membership” ROE incentive adder to file tariff updates that would terminate collection of the incentive adder. Initial comments on the proposed rule were filed on June 25, 2021, and reply comments were filed on July 26, 2021. The rulemaking remains pending before FERC. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the supplemental proposed rule. 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.

Allegheny Power Zone Transmission Formula Rate Filings

On October 29, 2020, MP, PE and WP filed tariff amendments with FERC to implement a forward-looking formula transmission rate, to be effective January 1, 2021. In addition, on October 30, 2020, KATCo filed a proposed new tariff to establish a forward-looking formula rate and requested that the new rate become effective January 1, 2021. In its filing, KATCo explained that while it currently owns no transmission assets, it may build new transmission facilities in the Allegheny zone, and that it may seek required state and federal authorizations to acquire transmission assets from PE and WP by January 1, 2022. These transmission rate filings were accepted for filing by FERC on December 31, 2020, effective January 1, 2021, subject to refund, pending further hearing and settlement procedures and were consolidated into a single proceeding. MP, PE and WP, and KATCo filed uncontested settlement agreements with FERC on January 18, 2023. Also on January 18, 2023, MP, PE and WP filed a motion for interim rates to implement certain aspects of the settled rate. The interim rates were approved by the FERC Chief Administrative Law Judge and took effect on January 1, 2023. As a result of the filed settlement, FirstEnergy recognized a $25 million pre-tax charge during the fourth quarter of 2022, which reflects the difference between amounts originally recorded as assets and amounts which will ultimately be recovered from customers as a result. On May 4, 2023, FERC issued an order approving the settlement agreement without condition or modification. Pursuant to the order, a compliance filing was filed on May 19, 2023, that implemented the terms of the settlement. On June 26, 2023, FERC issued a letter order approving the compliance filing.

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.
14. 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 December 31, 2023, outstanding guarantees and other assurances aggregated approximately $815 million, consisting of parental guarantees on behalf of its consolidated subsidiaries ($515 million) and other assurances ($300 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 December 31, 2023, $89 million of net cash collateral has been posted by FE or its subsidiaries and is included in "Prepaid taxes and other current assets" on FirstEnergy's Consolidated Balance Sheets. FE or its subsidiaries are holding $27 million of net cash collateral as of December 31, 2023, from certain generation suppliers, and such amount is included in "Other current liabilities" on FirstEnergy's Consolidated Balance Sheets.


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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 December 31, 2023:
Potential Collateral ObligationsUtilities and Transmission CompaniesFETotal
(In millions)
Contractual Obligations for Additional Collateral
Upon Further Downgrade$62 $— $62 
Surety Bonds (collateralized amount)(1)
86 79 165 
Total Exposure from Contractual Obligations$148 $79 $227 
(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 obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.

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, have separately appealed and filed 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, which remains pending. Oral argument is scheduled for February 21, 2024.

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Climate Change

In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris to reduce GHGs. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. On January 20, 2021, President Biden signed an executive order re-adopting the agreement on behalf of the U.S. 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 led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

FirstEnergy has pledged to achieve carbon neutrality by 2050 in GHGs within FirstEnergy’s direct operational control (Scope 1). With respect to our coal-fired plants in West Virginia, 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. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, 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 proposes stringent emissions limitations based on fuel type and unit retirement date. Comments on the proposed rule were submitted to the EPA on August 8, 2023. Depending on how final rules are ultimately implemented and 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. Public hearings on the proposed rules were held in April 2023 and comments were accepted through May 30, 2023. In

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the interim, the rule issued on August 31, 2020, remains in effect. 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 the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG 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 through the end of the first quarter of 2024, which request is pending technical review by the EPA. AE Supply continues to operate McElroy’s Run as a disposal facility for Pleasants Power Station, which is owned and operated by a non-affiliate.

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 the Consolidated Balance Sheets as of September 30, 2023, 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 $97 million have been accrued through December 31, 2023, of which, approximately $75 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 5 years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the DOJ’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. Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.

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


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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. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the review, inquiries and investigations, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.

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. 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 former chairman of the PUCO, Samuel Randazzo, 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. No contingency has been reflected in FirstEnergy’s consolidated financial statements, as a loss is neither probable, nor is a loss or range of loss reasonably estimable.

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, which the Sixth Circuit granted on November 16, 2023. 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 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

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prejudice of the cities’ suit. After a stay, pending final resolution of the United States v. Larry Householder, et al. criminal proceeding described above, the litigation has resumed pursuant to an order, dated March 15, 2023. Discovery is ongoing. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s section amended complaint, which the OAG opposed.

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.
•Miller v. Anderson, et al. (N.D. Ohio); 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); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the 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.

The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs. 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. If the S.D. Ohio’s final settlement approval is affirmed by the U.S. Court of Appeals for the Sixth Circuit, the settlement agreement is expected to resolve fully these shareholder derivative lawsuits.

On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022. On September 29, 2023, the N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit.

In letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that the Division was conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain all documents and information related to the same as such have been developed as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. FE paid the civil penalty on January 4, 2023 and it will not be recovered from customers. The first annual compliance monitoring report was submitted in December 2023.

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.

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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 13, “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.
15. SEGMENT INFORMATION

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission. FirstEnergy evaluates segment performance based on earnings attributable to FE from continuing operations.

The Regulated Distribution segment distributes electricity through FirstEnergy’s utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey, and Maryland. This segment also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are derived from primarily 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 Regulated Transmission segment.

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 majority of the purchase price is expected to be paid in cash upon closing, and the remainder will be payable by the issuance of a promissory note, which is expected to be repaid by the end of 2024. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the PPUC. In addition, pursuant to the FET P&SA II, FirstEnergy made the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by the end of the first quarter of 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s financial statements.

Corporate/Other reflects corporate support and other costs not charged or attributable to the Utilities 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. As of December 31, 2023, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2023, Corporate/Other had approximately $7.1 billion of external FE holding company debt.

2024 Segment Changes

Beginning in 2024, FirstEnergy changed its reportable segments to include Distribution, which will consist of the Ohio Companies and FE PA; Integrated, which will consist of MP, PE and JCP&L; and Stand-Alone Transmission, which will consist of FE's ownership in FET and KATCo. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo. Corporate/Other will reflect corporate support and other support costs not charged or attributable to the Utilities 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.

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Financial information for FirstEnergy’s business segments and reconciliations to consolidated amounts is presented below:
For the Years Ended December 31,
(In millions)202320222021
External revenues
Regulated Distribution$10,810 $10,569 $9,510 
Regulated Transmission2,049 1,863 1,608 
Corporate/Other11 27 14 
Reconciling Adjustments— — — 
Total external revenues$12,870 $12,459 $11,132 
Internal revenues
Regulated Distribution$228 $232 $201 
Regulated Transmission5 5 10 
Corporate/Other— — — 
Reconciling Adjustments(233)(237)(211)
Total internal revenues$— $— $— 
Total revenues$12,870 $12,459 $11,132 
Depreciation
Regulated Distribution$1,021 $967 $911 
Regulated Transmission367 335 325 
Corporate/Other4 7 3 
Reconciling Adjustments69 66 63 
Total depreciation$1,461 $1,375 $1,302 
Amortization (deferral) of regulatory assets, net
Regulated Distribution$(256)$(362)$260 
Regulated Transmission(5)(3)9 
Corporate/Other— — — 
Reconciling Adjustments— — — 
Total amortization (deferral) of regulatory assets, net$(261)$(365)$269 
DPA penalty
Corporate/Other$— $— $230 
Total DPA penalty$— $— $230 
Equity method investment earnings
Regulated Distribution$— $— $— 
Regulated Transmission— — — 
Corporate/Other175 168 31 
Reconciling Adjustments— — — 
Total equity method investment earnings$175 $168 $31 
Interest expense
Regulated Distribution$618 $526 $522 
Regulated Transmission256 230 247 
Corporate/Other334 350 382 
Reconciling Adjustments(84)(67)(12)
Total interest expense$1,124 $1,039 $1,139 
Income taxes (benefits)
Regulated Distribution$167 $251 $364 
Regulated Transmission179 110 127 
Corporate/Other(79)639 (171)
Reconciling Adjustments— — — 
Total income taxes$267 $1,000 $320 

132

For the Years Ended December 31,
(In millions)202320222021
Earnings (losses) attributable to FE from continuing operations
Regulated Distribution$740 $957 $1,288 
Regulated Transmission514 361 408 
Corporate/Other(131)(912)(457)
Reconciling Adjustments— — — 
Total earnings attributable to FE from continuing operations$1,123 $406 $1,239 
Cash Flows From Investing Activities:
Capital investments
Regulated Distribution$1,631 $1,605 $1,437 
Regulated Transmission1,610 1,192 958 
Corporate/Other115 51 92 
Reconciling Adjustments— — — 
Total capital investments$3,356 $2,848 $2,487 
As of December 31,
(In millions)20232022
Assets
Regulated Distribution$32,929 $31,749 
Regulated Transmission15,155 13,835 
Corporate/Other683 524 
Reconciling Adjustments— — 
Total assets$48,767 $46,108 
Goodwill
Regulated Distribution$5,004 $5,004 
Regulated Transmission614 614 
Corporate/Other— — 
Reconciling Adjustments— — 
Total goodwill$5,618 $5,618 

16. DISCONTINUED OPERATIONS

On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the Bankruptcy Court approved settlement payments totaling $853 million and a $125 million tax sharing payment to the FES Debtors. The settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company.

Income Taxes

As a result of the FES Debtors’ tax return deconsolidation, FirstEnergy recognized a worthless stock deduction, of approximately $4.9 billion, net of unrecognized tax benefits of $316 million, for the remaining tax basis in the stock of the FES Debtors. Based upon completion of the IRS’s review of the 2020 federal income tax return during fourth quarter 2021, FirstEnergy recognized the full tax benefit of the worthless stock deduction of approximately $5.2 billion, or $1.1 billion on a tax-effected basis, net of valuation allowances recorded against the state tax benefit ($21 million), eliminating associated uncertain tax position reserves.

Upon emergence, FirstEnergy paid the FES Debtors $125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest.

In conjunction with filing the 2020 consolidated federal income tax return during the third quarter of 2021, FirstEnergy computed a final federal NOL allocation between the FES Debtors and FirstEnergy consolidated that resulted in FirstEnergy recording an increase to the consolidated NOL carryforward of approximately $289 million ($61 million tax-effected).

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Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the years ended December 31, 2023, 2022, and 2021 were as follows:
For the Years Ended December 31,
(In millions)202320222021
Other expense, net— — (4)
Loss from discontinued operations, before tax— — (4)
Income tax benefit— — (1)
Loss from discontinued operations, net of tax— — (3)
Income tax expense (benefit), including worthless stock deduction21 — (47)
Gain (loss) on disposal, net of tax(21)— 47 
Income (loss) from discontinued operations(1)
$(21)$— $44 
(1) Income from discontinued operations is included in Corporate/Other.
On February 27, 2020, the FES Debtors emerged from bankruptcy and were deconsolidated from FirstEnergy’s consolidated federal income tax group. The bankruptcy, emergence and deconsolidation resulted in FirstEnergy recognizing certain income tax benefits and charges, which were classified as discontinued operations. During the third quarter of 2023, FirstEnergy recognized a $21 million tax-effected charge to income tax expense as a result of identifying an out of period adjustment related to the allocation of certain deferred income tax liabilities associated with the FES Debtors and their tax return deconsolidation in 2020. This adjustment was immaterial to the 2023 and prior period financial statements.

FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2023, 2022 and 2021:
For the Years Ended December 31,
(In millions)202320222021
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations$(21)$— $44 
Loss (gain) on disposal, net of tax 21 — (47)

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ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.
ITEM 9A.     CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

FirstEnergy, through the oversight of its Disclosure Committee, has established disclosure controls and procedures to ensure that information is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure, and ensure that information required to be disclosed in the reports FirstEnergy files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

The management of FirstEnergy, with the participation of the chief executive officer and chief financial officer, has 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 December 31, 2023. 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 December 31, 2023.

Management’s Report on Internal Control over Financial Reporting

Management of FirstEnergy is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. FirstEnergy’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting as of December 31, 2023, based on the framework in "Internal Control-Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2023.

The effectiveness of FirstEnergy’s internal control over financial reporting as of December 31, 2023 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2023, 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.
ITEM 9B.    OTHER INFORMATION

Trading Arrangements

During the quarter ended December 31, 2023, 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).

Director Resignation
On February 7, 2024, Sean Klimczak notified the FE Board of his intention to resign as a director of FE, effective the earlier of (i) the appointment of his replacement, or (ii) February 29, 2024. Mr. Klimczak’s resignation was not the result of any dispute or disagreement with FE or the FE Board on any matter relating to the operations, policies or practices of FirstEnergy. BIP Securities II-B L.P. intends to designate a substitute director acceptable to the FE Board to be appointed to the FE Board.

Pursuant to that certain Common Stock Purchase Agreement with BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., dated as of November 6, 2021, so long as BIP Securities II-B L.P. beneficially owns at least 75% of the shares of FE common stock acquired by it pursuant to the Common Stock Purchase Agreement, BIP Securities II-B L.P. will have the right to nominate one natural person for election to the FE Board.

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ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.
PART III
ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10 is incorporated herein by reference to FirstEnergy's 2024 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
ITEM 11.     EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2024 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The Item 403 of Regulation S-K information required by Item 12 is incorporated herein by reference to FirstEnergy's 2024 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

The following table contains information as of December 31, 2023, regarding compensation plans for which shares of FE common stock may be issued.
Plan categoryNumber of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and RightsWeighted-Average Exercise Price of Outstanding Options, Warrants and RightsNumber of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in First Column)
Equity compensation plans approved by security holders4,111,762 (1)$— (2)10,060,406 (3)
Equity compensation plans not approved by security holders(4)
— $— — 
Total4,111,762 $— 10,060,406 
(1) This number includes 1,918,675 shares subject to outstanding awards of stock based Restricted Stock Units granted under the ICP 2020 if paid at target for the three outstanding cycles, as well as 1,918,675 additional shares assuming maximum performance metrics are achieved for the 2021-2023, 2022-2024, and 2023-2025 cycles of stock based Restricted Stock Units, and 274,412 shares related to the DCPD that will be paid in stock.
(2) There are no outstanding options, therefore, no consideration is required from participants for the exercise or vesting of any outstanding equity compensation awards.
(3) Represents shares available for issuance, assuming maximum performance metrics are achieved (or approximately 4,841,463 under ICP 2015 and 7,137,618 under ICP 2020, available assuming performance at target) for the 2021-2023, 2022-2024, and 2023-2025 cycles of stock-based Restricted Stock Units, with respect to future awards under the ICP 2020 and future accruals of dividends on awards outstanding under ICP 2020. Additional shares may become available under the ICP 2020 due to cancellations, forfeitures, cash settlements or other similar circumstances with respect to outstanding awards.
(4) All equity compensation plans have been approved by security holders.
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated herein by reference to FirstEnergy’s 2024 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

136

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

A summary of the audit and all other fees for services rendered by PricewaterhouseCoopers LLP are as follows:
For the Years Ended December 31,
20232022
(In thousands)
Audit Fees(1)
$9,915 $7,523 
Audit-Related Fees(2)
— 190 
Tax Fees(3)
110 220 
All Other Fees(4)
282 720 
Total Fees$10,307 $8,653 
(1) Professional services rendered for the audits of FirstEnergy's and certain of its subsidiary annual financial statements and reviews of unaudited financial statements included in FirstEnergy's Quarterly Reports on Form 10-Q filings made with the SEC, and for services in connection with statutory and regulatory filings or engagements, including comfort letters, agreed upon procedures and consents for financings. 2023 audit fees also include newly required regulatory audits for certain subsidiaries and additional audit services to support the planned registration of certain subsidiaries with the SEC during 2024.
(2) Audit-related fees in 2022 were related to services rendered for EESG reporting assessments.
(3) Tax fees in 2023 and 2022 were primarily related to the performance of tax services related to the sale of interest in FET.
(4) All other fees in 2023 primarily reflect certain costs related to the ongoing SEC investigation. All other fees in 2022 primarily reflect certain costs incurred as a result of system implementation quality assurance services, the ongoing SEC investigation and software subscription fees.

Additional information required by this item is incorporated herein by reference to FirstEnergy’s 2024 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
PART IV
ITEM 15.     EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report on Form 10-K:
1. Financial Statements:
Management’s Report on Internal Control Over Financial Reporting for FirstEnergy Corp. is listed under Item 9A, "Controls and Procedures" herein.
Report of Independent Registered Public Accounting Firm (PCAOB ID 238) for FirstEnergy Corp. is listed under Item 8, "Financial Statements and Supplementary Data," herein.
The financial statements filed as a part of this report for FirstEnergy Corp. are listed under Item 8, "Financial Statements and Supplementary Data," herein.
2. Financial Statement Schedules:

N/A - Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

3. Exhibits

137

Exhibit
Number
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
10.1
10.2
10.3
10.4
10.5
10.6
10.7

138

Exhibit
Number
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22

139

Exhibit
Number
10.23
10.24
10.25
10.26
10.27
10.28(B)
10.29(B)
10.30(B)
10.31(B)
10.32(B)
10.33(B)
10.34(B)
10.35(B)
10.36(B)
10.37(B)
10.38(B)
10.39(B)
10.40(B)
10.41(B)
10.42(B)
10.43(B)
10.44(B)

140

Exhibit
Number
10.45(B)
10.46(B)
10.47(B)
10.48(B)
10.49(B)
10.50(B)
10.51(B)
10.52(B)
10.53(B)
10.54(B)
10.55(B)
10.56(B)
10.57(B)
10.58(B)
10.59
10.60
10.61(B)
10.62(B)
10.63(B)
10.64(B)
10.65(B)
10.66(B)
10.67(B)
10.68(B)
10.69(B)
10.70(B)

141

Exhibit
Number
10.71(B)
10.72(B)
10.71(B)
10.72(B)
10.72(B)
10.73(B)
14
21(A)
23(A)
31.1(A)
31.2(A)
32(A)
97(A)
101The following materials from the Annual Report on Form 10-K for FirstEnergy Corp. for the period ended December 31, 2023, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Stockholders' Equity, (iv) Consolidated Statements of Cash Flows, (v) related notes to these financial statements and (vi) document and entity information.
104Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document)
(A)Provided herein in electronic format as an exhibit.
(B)Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
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-K 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.

ITEM 16.     FORM 10-K SUMMARY
None.


142

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
FIRSTENERGY CORP.
BY:/s/ Brian X. Tierney
Brian X. Tierney
President and Chief Executive Officer
Date: February 13, 2024


143

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
FIRSTENERGY CORP.
/s/ Brian X. Tierney
Brian X. Tierney
President and Chief Executive Officer
(Principal Executive Officer)
/s/ John W. Somerhalder II
John W. Somerhalder II
Non-Executive Chair
/s/ Lisa Winston Hicks
Lisa Winston Hicks
Lead Independent Director
/s/ K. Jon Taylor/s/ Jason J. Lisowski
K. Jon TaylorJason J. Lisowski
Senior Vice President, Chief Financial Officer and StrategyVice President, Controller and Chief Accounting Officer
(Principal Financial Officer)(Principal Accounting Officer)
/s/ Jana T. Croom/s/ James F. O'Neil III
Jana T. CroomJames F. O'Neil III
DirectorDirector
/s/ Steven J. Demetriou/s/ Leslie M. Turner
Steven J. DemetriouLeslie M. Turner
DirectorDirector
/s/ Paul Kaleta/s/ Melvin D. Williams
Paul KaletaMelvin D. Williams
DirectorDirector
/s/ Sean T. Klimczak
Sean T. Klimczak
Director
Date: February 13, 2024

144