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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2025
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________________ to ___________________
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| Commission |
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Registrants; |
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I.R.S. Employer |
| File Numbers |
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Address and Telephone Number |
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States of Incorporation |
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Identification Nos. |
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| 333-21011 |
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FIRSTENERGY CORP. |
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Ohio |
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34-1843785 |
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341 White Pond Drive |
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Akron |
OH |
44320 |
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Telephone |
(800) |
736-3402 |
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| 1-3141 |
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JERSEY CENTRAL POWER & LIGHT COMPANY |
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New Jersey |
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21-0485010 |
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300 Madison Avenue |
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Morristown |
NJ |
07962 |
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Telephone |
(800) |
736-3402 |
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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| Registrant |
Title of Each Class |
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Trading Symbol |
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Name of Each Exchange on Which Registered |
| FirstEnergy Corp. |
Common Stock, $0.10 par value |
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FE |
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New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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| FirstEnergy Corp. |
Yes |
☑ |
No |
☐ |
| Jersey Central Power & Light Company |
Yes |
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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).
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| FirstEnergy Corp. |
Yes |
☑ |
No |
☐ |
| Jersey Central Power & Light Company |
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.
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| Large Accelerated Filer |
☑ FirstEnergy Corp. |
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| Accelerated Filer |
☐ N/A |
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| Non-accelerated Filer |
☑ Jersey Central Power & Light Company |
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| Smaller Reporting Company |
☐ N/A |
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| Emerging Growth Company |
☐ N/A |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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| FirstEnergy Corp. |
Yes |
☐ |
No |
☑ |
| Jersey Central Power & Light Company |
Yes |
☐ |
No |
☑ |
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
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OUTSTANDING |
| REGISTRANTS |
CLASS |
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As of March 31, 2025 |
| FirstEnergy Corp. |
Common Stock, $0.10 par value |
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577,156,244 |
| Jersey Central Power & Light Company |
Common Stock, $10 par value |
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13,628,447, all held by FirstEnergy Corp. |
This combined Form 10-Q is separately filed by FirstEnergy Corp. and Jersey Central Power & Light Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Jersey Central Power & Light Company makes no representation as to information relating to FirstEnergy Corp.
Jersey Central Power & Light Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
FirstEnergy Website and Other Social Media Sites and Applications
Each of the registrants’ 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 FirstEnergy’s website at investors.firstenergycorp.com. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.
These SEC filings are posted on FirstEnergy’s website as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Additionally, FirstEnergy routinely posts additional important information, including press releases, investor presentations, investor factbooks, regulatory activity updates, and notices of upcoming events under the “Investors” section of FirstEnergy’s website and recognizes FirstEnergy’s website as a channel of distribution to reach public investors and as a means of disclosing (including initially or exclusively) material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and Rich Site Summary feeds on the “Investors” page of FirstEnergy’s website. FirstEnergy also uses X (the social networking site formerly known as Twitter®), LinkedIn®, YouTube® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s website, X (the social networking site formerly known as Twitter®) handle, LinkedIn® profile, YouTube® channel or Facebook® page, and any corresponding applications of those sites, shall not be deemed incorporated into, or to be part of, this report.
TABLE OF CONTENTS
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Page |
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| Glossary of Terms |
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| Forward-Looking Statements |
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| Part I. Financial Information |
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| Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
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GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries, including JCP&L:
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| AE Supply |
Allegheny Energy Supply Company, LLC, a wholly owned unregulated generation subsidiary of FE |
| AGC |
Allegheny Generating Company, a wholly owned generation subsidiary of MP |
| ATSI |
American Transmission Systems, Incorporated, a wholly owned transmission subsidiary of FET |
| CEI |
The Cleveland Electric Illuminating Company, a wholly owned Ohio electric power company subsidiary of FE |
| Electric Companies |
OE, CEI, TE, FE PA, JCP&L, MP and PE |
| FE |
FirstEnergy Corp., a public electric power holding company |
| FE PA |
FirstEnergy Pennsylvania Electric Company, a wholly owned Pennsylvania electric power company subsidiary of FirstEnergy Pennsylvania Holding Company LLC, a wholly owned subsidiary of FE |
| FESC |
FirstEnergy Service Company, which provides legal, financial and other corporate support services |
| FET |
FirstEnergy Transmission, LLC a consolidated VIE of FE, and the parent company of ATSI, MAIT and TrAIL, and having a joint venture in PATH and Valley Link |
| FEV |
FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures |
| FirstEnergy |
FirstEnergy Corp., together with its consolidated subsidiaries |
| Global Holding |
Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC |
| JCP&L |
Jersey Central Power & Light Company, a wholly owned New Jersey electric power company subsidiary of FE |
| KATCo |
Keystone Appalachian Transmission Company, a wholly owned transmission subsidiary of FE |
| MAIT |
Mid-Atlantic Interstate Transmission, LLC, a wholly owned transmission subsidiary of FET |
| ME |
Metropolitan Edison Company, a former wholly owned Pennsylvania electric power company subsidiary of FE, which merged with and into FE PA on January 1, 2024 |
| MP |
Monongahela Power Company, a wholly owned West Virginia electric power company subsidiary of FE |
| OE |
Ohio Edison Company, a wholly owned Ohio electric power company subsidiary of FE |
| Ohio Companies |
CEI, OE and TE |
| PATH |
Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP |
| PATH-Allegheny |
PATH Allegheny Transmission Company, LLC |
| PATH-WV |
PATH West Virginia Transmission Company, LLC |
| PE |
The Potomac Edison Company, a wholly owned Maryland and West Virginia electric power company subsidiary of FE |
| Penn |
Pennsylvania Power Company, a former wholly owned Pennsylvania electric power company subsidiary of OE, which merged with and into FE PA on January 1, 2024 |
| Pennsylvania Companies |
ME, PN, Penn and WP, each of which merged with and into FE PA on January 1, 2024 |
| PN |
Pennsylvania Electric Company, a former wholly owned Pennsylvania electric power company subsidiary of FE, which merged with and into FE PA on January 1, 2024 |
| Registrants |
FE and JCP&L |
| Signal Peak |
Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana |
| TE |
The Toledo Edison Company, a wholly owned Ohio electric power company subsidiary of FE |
| TrAIL |
Trans-Allegheny Interstate Line Company, a wholly owned transmission subsidiary of FET |
| Transmission Companies |
ATSI, MAIT, TrAIL and KATCo |
| Valley Link |
Valley Link Transmission Company, LLC, a holding company formed by FET, Dominion High Voltage MidAtlantic, Inc., and Transource Energy, LLC, on November 24, 2024 |
| WP |
West Penn Power Company, a former wholly owned Pennsylvania electric power company subsidiary of FE, which merged with and into FE PA on January 1, 2024 |
|
|
|
|
|
|
| The following abbreviations and acronyms may be used to identify frequently used terms in this report: |
|
|
| 2026 Convertible Notes |
FE's 4.00% convertible senior notes, due 2026 |
| ACE |
Affordable Clean Energy |
| AEP |
American Electric Power Company, Inc. |
| AFS |
Available-for-sale |
| AFSI |
Adjusted Financial Statement Income |
| AFUDC |
Allowance for Funds Used During Construction |
| AMI |
Advanced Metering Infrastructure |
| AMT |
Alternative Minimum Tax |
| AOCI |
Accumulated Other Comprehensive Income (Loss) |
| ARO |
Asset Retirement Obligation |
| ASU |
Accounting Standards Update |
| BGS |
Basic Generation Service |
| Brookfield |
North American Transmission Company II L.P., a controlled investment vehicle entity of Brookfield Infrastructure Partners |
| CAA |
Clean Air Act |
| CCR |
Coal Combustion Residual |
| CERCLA |
Comprehensive Environmental Response, Compensation, and Liability Act of 1980 |
| CFR |
Code of Federal Regulations |
CO2 |
Carbon Dioxide |
| CODM |
Chief Operating Decision Maker |
| CPP |
EPA's Clean Power Plan |
| CSAPR |
Cross-State Air Pollution Rule |
| D.C. Circuit |
U.S. Court of Appeals for the District of Columbia Circuit |
| DCR |
Delivery Capital Recovery |
| DMR |
Distribution Modernization Rider |
| DOE |
U.S. Department of Energy |
| DPA |
Deferred Prosecution Agreement entered into on July 21, 2021, between FE and the U.S. Attorney’s Office for the S.D. Ohio |
| DSIC |
Distribution System Improvement Charge |
| EDC |
Electric Distribution Company |
| EEI |
The Edison Electric Institute |
| EGS |
Electric Generation Supplier |
| EGU |
Electric Generation Unit |
| EH |
Energy Harbor Corp. |
| ELG |
Effluent Limitation Guidelines |
| EmPOWER Maryland |
EmPOWER Maryland Energy Efficiency Act |
| ENEC |
Expanded Net Energy Cost |
| Energize365 |
FirstEnergy's Transmission and Distribution Infrastructure Investment Program. |
| EnergizeNJ |
JCP&L's second Infrastructure Investment Program |
| EPA |
U.S. Environmental Protection Agency |
| EPS |
Earnings per Share |
| ESP |
Electric Security Plan |
| Exchange Act |
Securities and Exchange Act of 1934, as amended |
| FASB |
Financial Accounting Standards Board |
| FE Board |
FE Board of Directors |
| FE Revolving Facility |
FE and the Electric Companies’ former five-year syndicated revolving credit facility, as amended, and replaced by the 2021 Credit Facilities on October 18, 2021 |
| FERC |
Federal Energy Regulatory Commission |
| FET Equity Interest Sale |
Sale of an additional 30% membership interest of FET, such that Brookfield will own 49.9% of FET |
|
|
|
|
|
|
| FIP |
Federal Implementation Plan |
| Fitch |
Fitch Ratings Service |
| FTR |
Financial Transmission Right |
| GAAP |
Generally Accepted Accounting Principles in the United States |
| GHG |
Greenhouse Gas |
| HB 6 |
House Bill 6, as passed by Ohio's 133rd General Assembly |
| IBEW |
International Brotherhood of Electrical Workers |
| IRA of 2022 |
Inflation Reduction Act of 2022 |
| IRS |
Internal Revenue Service |
| kV |
Kilovolt |
| LOC |
Letter of Credit |
| LTIIP |
Long-Term Infrastructure Improvement Plan |
| MDPSC |
Maryland Public Service Commission |
| MGP |
Manufactured Gas Plants |
| Moody’s |
Moody’s Investors Service, Inc. |
| MW |
Megawatt |
| MWh |
Megawatt-hour |
| NCI |
Noncontrolling Interest |
| NERC |
North American Electric Reliability Corporation |
| NJBPU |
New Jersey Board of Public Utilities |
| NOL |
Net Operating Loss |
| NOx |
Nitrogen Oxide |
| NYPSC |
New York State Public Service Commission |
| OAG |
Ohio Attorney General |
| OCC |
Ohio Consumers' Counsel |
| ODSA |
Ohio Development Service Agency |
| Ohio Stipulation |
Stipulation and Recommendation, dated November 1, 2021, entered into by and among the Ohio Companies, the OCC, PUCO staff, and several other signatories |
| OPEB |
Other Postemployment Benefits |
| OPEIU |
Office and Professional Employees International Union |
| OPIC |
Other paid-in capital |
| OSMRE |
U.S. Department of the Interior, Office of Surface Mining Reclamation and Enforcement |
| OVEC |
Ohio Valley Electric Corporation |
| PA Consolidation |
Consolidation of the Pennsylvania Companies on January 1st, 2024 |
| PJM |
PJM Interconnection, LLC, an RTO |
| PJM Region |
The 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 Tariff |
PJM Open Access Transmission Tariff |
| PPA |
Purchase Power Agreement |
| PPUC |
Pennsylvania Public Utility Commission |
| PUCO |
Public Utilities Commission of Ohio |
| Regulation FD |
Regulation Fair Disclosure promulgated by the SEC |
| RTEP |
Regional Transmission Expansion Plan |
| RFC |
ReliabilityFirst Corporation |
| ROE |
Return on Equity |
| RTO |
Regional Transmission Organization |
| S&P |
Standard & Poor’s Ratings Service |
| S&P 500 |
Standard & Poor’s 500 index |
| S.D. Ohio |
Federal District Court, Southern District of Ohio |
| SEC |
U.S. Securities and Exchange Commission |
|
|
|
|
|
|
| Securities Act |
Securities Act of 1933, as amended |
| SEET |
Significantly Excessive Earnings Test |
| Sixth Circuit |
U.S. Court of Appeals for the Sixth Circuit |
| SIP |
State Implementation Plan(s) under the CAA |
SO2 |
Sulfur Dioxide |
| SOFR |
Secured Overnight Financing Rate |
| SOS |
Standard Offer Service |
| SPE |
Special Purpose Entity |
| Tax Act |
Tax Cuts and Jobs Act adopted December 22, 2017 |
| U.S. |
United States |
| UWUA |
Utility Workers Union of America |
| Valley Link LLCA |
Amended and Restated Operating Agreement of Valley Link |
| VEPCO |
Virginia Electric and Power Company, a subsidiary of Dominion Energy, Inc. |
| VIE |
Variable Interest Entity |
| VSCC |
Virginia State Corporation Commission |
| WVPSC |
Public Service Commission of West Virginia |
Forward-Looking Statements: This Form 10-Q includes forward-looking statements based on information currently available to the Registrants’ management and unless the context requires otherwise, references to “we,” “us,” “our” and “FirstEnergy” refer to the Registrants. 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, and settlements with the OAG's office and the SEC.
•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.
•Changes in national and regional economic conditions, including recession, volatile interest rates, inflationary pressure, supply chain disruptions, higher fuel costs, and workforce impacts, affecting us and/or our customers and the vendors with which we do business.
•Variations in weather, such as mild seasonal weather variations and severe weather conditions (including events caused, or exacerbated, by climate change, such as wildfires, hurricanes, flooding, droughts, high wind events and extreme heat events) and other natural disasters, which may result in increased storm restoration expenses or material liability and negatively affect future operating results.
•The potential liabilities and increased costs arising from regulatory actions or outcomes in response to severe weather conditions and other natural disasters.
•Legislative and regulatory developments, and executive orders, including, but not limited to, matters related to rates, energy regulatory policies, compliance and enforcement activity, cyber security, climate change, and diversity, equity and inclusion.
•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, and the loss of FE’s status as a well-known seasoned issuer.
•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 accomplish or realize anticipated benefits through establishing a culture of continuous improvement and our other strategic and financial goals, including, but not limited to, executing Energize365, our transmission and distribution investment plan, executing on our rate filing strategy, controlling costs, improving credit metrics, maintaining investment grade ratings, strengthening our balance sheet and growing earnings.
•Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts may negatively impact our forecasted growth rate, results of operations and may also cause it to make contributions to its pension sooner or in amounts that are larger than currently anticipated.
•Changes in assumptions regarding factors such as economic conditions within our territories, the reliability of our transmission and distribution system, our generation resource planning in West Virginia, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities.
•Human capital management challenges, including among other things, attracting and retaining appropriately trained and qualified employees and labor disruptions by our unionized workforce.
•Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets, including those sites impacted by the legacy CCR rules that were finalized during 2024, and the EPA’s reconsideration of such rule.
•Changes to environmental laws and regulations, including, but not limited to, federal and state rules related to climate change, and potential changes to such laws and regulations as a result of the U.S. presidential administration.
•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.
•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.
•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.
•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 and potential changes to such laws and regulations as a result of the new U.S. presidential administration.
•The ability to meet our publicly-disclosed goals relating to climate-related matters, opportunities, improvements, and efficiencies, including FirstEnergy’s GHG reduction goals.
•The risks and other factors discussed from time to time in our SEC filings.
Dividends declared from time to time on FE’s common stock during any period may in the aggregate vary from prior periods due to circumstances considered by the FE Board at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding FirstEnergy’s Climate Strategy, including FirstEnergy’s GHG emission reduction goals, are not an indication that these statements are necessarily material to investors or required to be disclosed in FE’s 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.
PART I. FINANCIAL INFORMATION
ITEM I. Financial Statements
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
|
|
| (In millions, except per share amounts) |
|
2025 |
|
2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| REVENUES: |
|
|
|
|
|
|
|
|
| Distribution services and retail generation |
|
$ |
3,081 |
|
|
$ |
2,695 |
|
|
|
|
|
| Transmission |
|
586 |
|
|
515 |
|
|
|
|
|
| Other |
|
98 |
|
|
77 |
|
|
|
|
|
Total revenues(1) |
|
3,765 |
|
|
3,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
| Fuel |
|
149 |
|
|
105 |
|
|
|
|
|
| Purchased power |
|
1,088 |
|
|
1,036 |
|
|
|
|
|
| Other operating expenses |
|
1,034 |
|
|
1,006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Provision for depreciation |
|
411 |
|
|
381 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Deferral of regulatory assets, net |
|
(10) |
|
|
(164) |
|
|
|
|
|
| General taxes |
|
339 |
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total operating expenses |
|
3,011 |
|
|
2,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| OPERATING INCOME |
|
754 |
|
|
612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| OTHER INCOME (EXPENSE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investment earnings, net (Note 1) |
|
— |
|
|
21 |
|
|
|
|
|
| Miscellaneous income, net |
|
36 |
|
|
44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Interest expense |
|
(288) |
|
|
(305) |
|
|
|
|
|
| Capitalized financing costs |
|
38 |
|
|
30 |
|
|
|
|
|
| Total other expense |
|
(214) |
|
|
(210) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| INCOME BEFORE INCOME TAXES |
|
540 |
|
|
402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| INCOME TAXES |
|
126 |
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NET INCOME |
|
$ |
414 |
|
|
$ |
267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income attributable to noncontrolling interest |
|
54 |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP. |
|
$ |
360 |
|
|
$ |
253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| COMPREHENSIVE INCOME ATTRIBUTABLE TO FIRSTENERGY CORP. |
|
$ |
360 |
|
|
$ |
253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER SHARE ATTRIBUTABLE TO FIRSTENERGY CORP. (Note 3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Basic |
|
$ |
0.62 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Diluted |
|
$ |
0.62 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: |
|
|
|
|
|
|
|
|
| Basic |
|
577 |
|
|
574 |
|
|
|
|
|
| Diluted |
|
578 |
|
|
576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes excise and gross receipts tax collections of $123 million and $115 million during the three months ended March 31, 2025 and 2024, respectively.
See Combined Notes to Financial Statements of the Registrants.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions, except share amounts) |
|
|
March 31,
2025 |
|
December 31,
2024 |
| ASSETS |
|
|
|
|
|
| CURRENT ASSETS: |
|
|
|
|
|
| Cash and cash equivalents |
|
|
$ |
132 |
|
|
$ |
111 |
|
| Restricted cash |
|
|
31 |
|
|
43 |
|
| Receivables- |
|
|
|
|
|
| Customers |
|
|
1,624 |
|
|
1,585 |
|
| Less — Allowance for uncollectible customer receivables |
|
|
50 |
|
|
55 |
|
|
|
|
1,574 |
|
|
1,530 |
|
|
|
|
|
|
|
Other, net of allowance for uncollectible accounts of $9 in 2025 and $6 in 2024 |
|
|
314 |
|
|
303 |
|
|
|
|
|
|
|
| Materials and supplies, at average cost |
|
|
567 |
|
|
549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Prepaid taxes and other |
|
|
341 |
|
|
240 |
|
|
|
|
|
|
|
| |
|
|
2,959 |
|
|
2,776 |
|
| PROPERTY, PLANT AND EQUIPMENT: |
|
|
|
|
|
| In service |
|
|
53,543 |
|
|
52,896 |
|
| Less — Accumulated provision for depreciation |
|
|
14,774 |
|
|
14,548 |
|
| |
|
|
38,769 |
|
|
38,348 |
|
| Construction work in progress |
|
|
2,932 |
|
|
2,754 |
|
| |
|
|
41,701 |
|
|
41,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| INVESTMENTS AND OTHER NONCURRENT ASSETS: |
|
|
|
|
|
| Goodwill |
|
|
5,618 |
|
|
5,618 |
|
Investments (Note 6) |
|
|
657 |
|
|
652 |
|
| Regulatory assets |
|
|
636 |
|
|
617 |
|
| Other |
|
|
1,200 |
|
|
1,279 |
|
|
|
|
|
|
|
| |
|
|
8,111 |
|
|
8,166 |
|
| TOTAL ASSETS |
|
|
$ |
52,771 |
|
|
$ |
52,044 |
|
|
|
|
|
|
|
| LIABILITIES AND EQUITY |
|
|
|
|
|
| CURRENT LIABILITIES: |
|
|
|
|
|
| Currently payable long-term debt |
|
|
$ |
1,928 |
|
|
$ |
977 |
|
| Short-term borrowings |
|
|
1,635 |
|
|
550 |
|
| Accounts payable |
|
|
1,516 |
|
|
1,575 |
|
|
|
|
|
|
|
| Accrued interest |
|
|
280 |
|
|
269 |
|
| Accrued taxes |
|
|
715 |
|
|
727 |
|
| Accrued compensation and benefits |
|
|
257 |
|
|
205 |
|
|
|
|
|
|
|
| Customer deposits |
|
|
236 |
|
|
233 |
|
| Dividends payable |
|
|
257 |
|
|
245 |
|
| Other |
|
|
290 |
|
|
216 |
|
|
|
|
|
|
|
| |
|
|
7,114 |
|
|
4,997 |
|
| NONCURRENT LIABILITIES: |
|
|
|
|
|
| Long-term debt and other long-term obligations |
|
|
21,223 |
|
|
22,496 |
|
| Accumulated deferred income taxes |
|
|
5,740 |
|
|
5,613 |
|
| Retirement benefits |
|
|
1,698 |
|
|
1,698 |
|
| Regulatory liabilities |
|
|
998 |
|
|
995 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other |
|
|
2,136 |
|
|
2,525 |
|
|
|
|
|
|
|
| |
|
|
31,795 |
|
|
33,327 |
|
| TOTAL LIABILITIES |
|
|
38,909 |
|
|
38,324 |
|
|
|
|
|
|
|
| EQUITY: |
|
|
|
|
|
| Common stockholders’ equity- |
|
|
|
|
|
Common stock, $0.10 par value, authorized 700,000,000 shares - 577,156,244 and 576,612,245 shares outstanding as of March 31, 2025 and December 31, 2024, respectively. |
|
|
58 |
|
|
58 |
|
|
|
|
|
|
|
| Other paid-in capital |
|
|
12,377 |
|
|
12,368 |
|
| Accumulated other comprehensive loss |
|
|
(14) |
|
|
(14) |
|
| Retained earnings |
|
|
146 |
|
|
43 |
|
| Total common stockholders’ equity |
|
|
12,567 |
|
|
12,455 |
|
| Noncontrolling interest |
|
|
1,295 |
|
|
1,265 |
|
|
|
|
|
|
|
| TOTAL EQUITY |
|
|
13,862 |
|
|
13,720 |
|
|
|
|
|
|
|
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 10) |
|
|
|
|
|
|
|
|
|
|
|
| TOTAL LIABILITIES AND EQUITY |
|
|
$ |
52,771 |
|
|
$ |
52,044 |
|
|
|
|
|
|
|
See Combined Notes to Financial Statements of the Registrants.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2025 |
|
|
Common stock |
|
OPIC |
|
AOCI |
|
Retained earnings (Accumulated deficit) |
|
Total Common Stockholders’ Equity |
|
NCI |
|
Total Equity |
| (In millions) |
|
Shares |
|
Amount |
|
|
|
|
|
| Balance, January 1, 2025 |
|
577 |
|
|
$ |
58 |
|
|
$ |
12,368 |
|
|
$ |
(14) |
|
|
$ |
43 |
|
|
$ |
12,455 |
|
|
$ |
1,265 |
|
|
$ |
13,720 |
|
| Net income |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
360 |
|
|
360 |
|
|
54 |
|
|
414 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Stock Investment Plan and share-based benefit plans |
|
— |
|
|
— |
|
|
9 |
|
|
— |
|
|
— |
|
|
9 |
|
|
— |
|
|
9 |
|
Cash dividends declared on common stock ($0.445 per share in March) |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(257) |
|
|
(257) |
|
|
— |
|
|
(257) |
|
| Noncontrolling interest distributions declared |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(24) |
|
|
(24) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance, March 31, 2025 |
|
577 |
|
|
$ |
58 |
|
|
$ |
12,377 |
|
|
$ |
(14) |
|
|
$ |
146 |
|
|
$ |
12,567 |
|
|
$ |
1,295 |
|
|
$ |
13,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2024 |
|
|
|
|
Common stock |
|
OPIC |
|
AOCI |
|
Accumulated deficit |
|
Total Common Stockholders’ Equity |
|
NCI |
|
Total Equity |
|
|
| (In millions) |
|
Shares |
|
Amount |
|
|
|
|
|
|
|
| Balance, January 1, 2024 |
|
574 |
|
|
$ |
57 |
|
|
$ |
10,494 |
|
|
$ |
(17) |
|
|
$ |
(97) |
|
|
$ |
10,437 |
|
|
$ |
479 |
|
|
$ |
10,916 |
|
|
|
| Net income |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
253 |
|
|
253 |
|
|
14 |
|
|
267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Stock Investment Plan and share-based benefit plans |
|
2 |
|
|
— |
|
|
9 |
|
|
— |
|
|
— |
|
|
9 |
|
|
— |
|
|
9 |
|
|
|
Cash dividends declared on common stock ($0.425 per share in March) |
|
— |
|
|
— |
|
|
(88) |
|
|
— |
|
|
(156) |
|
|
(244) |
|
|
— |
|
|
(244) |
|
|
|
| FET Equity Interest Sale |
|
— |
|
|
— |
|
|
1,942 |
|
|
— |
|
|
— |
|
|
1,942 |
|
|
731 |
|
|
2,673 |
|
|
|
| Noncontrolling interest distributions declared |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(8) |
|
|
(8) |
|
|
|
| Balance, March 31, 2024 |
|
576 |
|
|
$ |
57 |
|
|
$ |
12,357 |
|
|
$ |
(17) |
|
|
$ |
— |
|
|
$ |
12,397 |
|
|
$ |
1,216 |
|
|
$ |
13,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Combined Notes to Financial Statements of the Registrants.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| (In millions) |
|
2025 |
|
2024 |
| CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
| Net income |
|
$ |
414 |
|
|
$ |
267 |
|
| Adjustments to reconcile net income to net cash from operating activities- |
|
|
|
|
| Depreciation, amortization and impairments |
|
408 |
|
|
276 |
|
|
|
|
|
|
|
|
|
|
|
| Deferred income taxes and investment tax credits, net |
|
97 |
|
|
112 |
|
|
|
|
|
|
| Employee benefit costs, net |
|
(3) |
|
|
(17) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Transmission revenue collections, net |
|
40 |
|
|
48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Changes in current assets and liabilities- |
|
|
|
|
| Receivables |
|
(55) |
|
|
(85) |
|
| Materials and supplies |
|
(18) |
|
|
(26) |
|
| Prepaid taxes and other current assets |
|
(108) |
|
|
(172) |
|
| Accounts payable |
|
25 |
|
|
(1) |
|
| Accrued taxes |
|
(157) |
|
|
(176) |
|
| Accrued interest |
|
11 |
|
|
13 |
|
| Accrued compensation and benefits |
|
(7) |
|
|
(178) |
|
| Other current liabilities |
|
(16) |
|
|
(18) |
|
|
|
|
|
|
| Collateral, net |
|
37 |
|
|
(25) |
|
| Employee benefit plan funding and related payments |
|
(12) |
|
|
(20) |
|
| Other |
|
(19) |
|
|
(38) |
|
| Net cash provided from (used for) operating activities |
|
637 |
|
|
(40) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
| Capital investments |
|
(1,005) |
|
|
(790) |
|
|
|
|
|
|
| Sales of investment securities held in trusts |
|
27 |
|
|
13 |
|
| Purchases of investment securities held in trusts |
|
(30) |
|
|
(16) |
|
|
|
|
|
|
| Asset removal costs |
|
(84) |
|
|
(78) |
|
| Other |
|
(1) |
|
|
1 |
|
| Net cash used for investing activities |
|
(1,093) |
|
|
(870) |
|
|
|
|
|
|
| CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
| New financing- |
|
|
|
|
| Long-term debt |
|
— |
|
|
150 |
|
| Short-term borrowings, net |
|
1,085 |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
| Redemptions and repayments- |
|
|
|
|
| Long-term debt |
|
(324) |
|
|
(23) |
|
| Short-term borrowings, net |
|
— |
|
|
(525) |
|
|
|
|
|
|
| Proceeds from FET Equity Interest Sale |
|
— |
|
|
2,300 |
|
| Noncontrolling interest cash distributions |
|
(24) |
|
|
(8) |
|
|
|
|
|
|
|
|
|
|
|
| Common stock dividend payments |
|
(245) |
|
|
(235) |
|
| Debt issuance and redemption costs, and other |
|
(27) |
|
|
(13) |
|
| Net cash provided from financing activities |
|
465 |
|
|
1,646 |
|
|
|
|
|
|
| Net change in cash, cash equivalents, and restricted cash |
|
9 |
|
|
736 |
|
| Cash, cash equivalents, and restricted cash at beginning of period |
|
154 |
|
|
179 |
|
| Cash, cash equivalents, and restricted cash at end of period |
|
$ |
163 |
|
|
$ |
915 |
|
|
|
|
|
|
| SUPPLEMENTAL CASH FLOW INFORMATION: |
|
|
|
|
| Significant non-cash transactions: |
|
|
|
|
| Accrued capital investments |
|
$ |
285 |
|
|
$ |
224 |
|
| McElroy Run Transfer |
|
$ |
130 |
|
|
$ |
— |
|
See Combined Notes to Financial Statements of the Registrants.
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
|
|
| (In millions) |
|
2025 |
|
2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| REVENUES |
|
$ |
566 |
|
|
$ |
466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
| Purchased power |
|
298 |
|
|
248 |
|
|
|
|
|
|
Other operating expenses(1) |
|
145 |
|
|
187 |
|
|
|
|
|
|
| Provision for depreciation |
|
65 |
|
|
61 |
|
|
|
|
|
|
| Deferral of regulatory assets, net |
|
(22) |
|
|
(39) |
|
|
|
|
|
|
| General taxes |
|
6 |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total operating expenses |
|
492 |
|
|
462 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| OPERATING INCOME |
|
74 |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| OTHER INCOME (EXPENSE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Miscellaneous income, net |
|
12 |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Interest expense - other |
|
(29) |
|
|
(30) |
|
|
|
|
|
|
| Interest expense - affiliates |
|
(1) |
|
|
(4) |
|
|
|
|
|
|
| Capitalized financing costs |
|
9 |
|
|
7 |
|
|
|
|
|
|
| Total other expense |
|
(9) |
|
|
(16) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) |
|
65 |
|
|
(12) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| INCOME TAXES (BENEFITS) |
|
16 |
|
|
(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NET INCOME (LOSS) |
|
$ |
49 |
|
|
$ |
(8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| COMPREHENSIVE INCOME (LOSS) |
|
$ |
49 |
|
|
$ |
(8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) During the three months ended March 31, 2025 and 2024, $54 million and $46 million, respectively, of affiliated operating expenses were incurred, a portion of which is capitalized.
See Combined Notes to Financial Statements of the Registrants.
JERSEY CENTRAL POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions, except share amounts) |
|
March 31, 2025 |
|
December 31, 2024 |
| ASSETS |
|
|
|
|
| CURRENT ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Receivables - |
|
|
|
|
| Customers |
|
$ |
262 |
|
|
$ |
284 |
|
| Less — Allowance for uncollectible customer receivables |
|
5 |
|
|
6 |
|
|
|
257 |
|
|
278 |
|
| Affiliated companies |
|
8 |
|
|
44 |
|
| Other |
|
41 |
|
|
28 |
|
|
|
|
|
|
| Prepaid taxes and other |
|
31 |
|
|
29 |
|
|
|
|
|
|
|
|
337 |
|
|
379 |
|
| PROPERTY, PLANT AND EQUIPMENT: |
|
|
|
|
| In service |
|
8,807 |
|
|
8,697 |
|
| Less — Accumulated provision for depreciation |
|
2,415 |
|
|
2,409 |
|
| |
|
6,392 |
|
|
6,288 |
|
| Construction work in progress |
|
661 |
|
|
620 |
|
| |
|
7,053 |
|
|
6,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| INVESTMENTS AND OTHER NONCURRENT ASSETS: |
|
|
|
|
| Goodwill |
|
1,811 |
|
|
1,811 |
|
| Investments |
|
283 |
|
|
282 |
|
| Regulatory assets |
|
292 |
|
|
265 |
|
| Prepaid OPEB costs |
|
219 |
|
|
215 |
|
| Other |
|
78 |
|
|
67 |
|
| |
|
2,683 |
|
|
2,640 |
|
| TOTAL ASSETS |
|
$ |
10,073 |
|
|
$ |
9,927 |
|
|
|
|
|
|
| LIABILITIES AND COMMON STOCKHOLDER’S EQUITY |
|
|
|
|
| CURRENT LIABILITIES: |
|
|
|
|
| Currently payable long-term debt |
|
$ |
651 |
|
|
$ |
1 |
|
| Short-term borrowings - |
|
|
|
|
| Affiliated companies |
|
76 |
|
|
22 |
|
|
|
|
|
|
| Accounts payable - |
|
|
|
|
| Affiliated companies |
|
18 |
|
|
1 |
|
| Other |
|
182 |
|
|
176 |
|
| Accrued compensation and benefits |
|
30 |
|
|
33 |
|
| Customer deposits |
|
34 |
|
|
34 |
|
| Accrued taxes |
|
14 |
|
|
21 |
|
| Accrued interest |
|
30 |
|
|
23 |
|
|
|
|
|
|
| Other |
|
59 |
|
|
34 |
|
| |
|
1,094 |
|
|
345 |
|
| NONCURRENT LIABILITIES: |
|
|
|
|
| Long-term debt and other long-term obligations |
|
1,687 |
|
|
2,339 |
|
| Accumulated deferred income taxes, net |
|
1,223 |
|
|
1,196 |
|
| Nuclear fuel disposal costs |
|
237 |
|
|
235 |
|
| Retirement benefits |
|
69 |
|
|
71 |
|
|
|
|
|
|
| Other |
|
765 |
|
|
764 |
|
|
|
3,981 |
|
|
4,605 |
|
| TOTAL LIABILITIES |
|
5,075 |
|
|
4,950 |
|
|
|
|
|
|
| COMMON STOCKHOLDER'S EQUITY: |
|
|
|
|
Common stock, $10 par value, authorized 16,000,000 shares - 13,628,447 shares outstanding |
|
136 |
|
|
136 |
|
| Other paid-in capital |
|
3,525 |
|
|
3,523 |
|
| Accumulated other comprehensive loss |
|
(4) |
|
|
(4) |
|
| Retained earnings |
|
1,341 |
|
|
1,322 |
|
| TOTAL COMMON STOCKHOLDER’S EQUITY |
|
4,998 |
|
|
4,977 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 10) |
|
|
|
|
|
|
|
|
|
| TOTAL LIABILITIES AND EQUITY |
|
$ |
10,073 |
|
|
$ |
9,927 |
|
|
|
|
|
|
|
|
|
|
|
See Combined Notes to Financial Statements of the Registrants.
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2025 |
|
|
Common Stock |
|
|
|
|
|
|
|
|
| (In millions, except share amounts) |
|
Number of Shares |
|
Carrying Value |
|
Other Paid-In Capital |
|
AOCI |
|
Retained Earnings |
|
Total Stockholder's Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance, January 1, 2025 |
|
13,628,447 |
|
|
$ |
136 |
|
|
$ |
3,523 |
|
|
$ |
(4) |
|
|
$ |
1,322 |
|
|
$ |
4,977 |
|
| Net income |
|
|
|
|
|
|
|
|
|
49 |
|
|
49 |
|
Stock-based compensation(1) |
|
|
|
|
|
2 |
|
|
|
|
|
|
2 |
|
| Common stock dividends declared |
|
|
|
|
|
|
|
|
|
(30) |
|
|
(30) |
|
| Balance, March 31, 2025 |
|
13,628,447 |
|
|
$ |
136 |
|
|
$ |
3,525 |
|
|
$ |
(4) |
|
|
$ |
1,341 |
|
|
$ |
4,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2024 |
|
|
Common Stock |
|
|
|
|
|
|
|
|
| (In millions, except share amounts) |
|
Number of Shares |
|
Carrying Value |
|
Other Paid-In Capital |
|
AOCI |
|
Retained Earnings |
|
Total Stockholder's Equity |
| Balance, January 1, 2024 |
|
13,628,447 |
|
|
$ |
136 |
|
|
$ |
2,777 |
|
|
$ |
(5) |
|
|
$ |
1,224 |
|
|
$ |
4,132 |
|
| Net loss |
|
|
|
|
|
|
|
|
|
(8) |
|
|
(8) |
|
Stock-based compensation(1) |
|
|
|
|
|
2 |
|
|
|
|
|
|
2 |
|
| Equity contribution from parent |
|
|
|
|
|
140 |
|
|
|
|
|
|
140 |
|
| Balance, March 31, 2024 |
|
13,628,447 |
|
|
$ |
136 |
|
|
$ |
2,919 |
|
|
$ |
(5) |
|
|
$ |
1,216 |
|
|
$ |
4,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) In the form of FE common equity granted to certain JCP&L employees.
See Combined Notes to Financial Statements of the Registrants.
JERSEY CENTRAL POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
|
|
| (In millions) |
|
2025 |
|
2024 |
|
|
|
|
| CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
| Net income (loss) |
|
$ |
49 |
|
|
$ |
(8) |
|
|
|
|
|
| Adjustments to reconcile net income to net cash from operating activities- |
|
|
|
|
|
|
|
|
| Depreciation, amortization and impairments |
|
43 |
|
|
71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Transmission revenue collections, net |
|
8 |
|
|
9 |
|
|
|
|
|
| Deferred income taxes and investment tax credits, net |
|
23 |
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Spent nuclear fuel disposal trust income |
|
3 |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Employee benefit costs, net |
|
(6) |
|
|
(7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Changes in current assets and liabilities- |
|
|
|
|
|
|
|
|
| Receivables |
|
44 |
|
|
(15) |
|
|
|
|
|
| Prepaid taxes and other current assets |
|
(2) |
|
|
7 |
|
|
|
|
|
| Accounts payable |
|
28 |
|
|
19 |
|
|
|
|
|
| Accrued taxes |
|
(7) |
|
|
(3) |
|
|
|
|
|
| Accrued interest |
|
7 |
|
|
3 |
|
|
|
|
|
| Accrued compensation and benefits |
|
(5) |
|
|
(12) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other current liabilities |
|
5 |
|
|
(2) |
|
|
|
|
|
| Collateral, net |
|
19 |
|
|
2 |
|
|
|
|
|
| Employee benefit plan funding and related payments |
|
— |
|
|
(7) |
|
|
|
|
|
| Other |
|
(4) |
|
|
(4) |
|
|
|
|
|
| Net cash provided from operating activities |
|
205 |
|
|
83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
| Capital investments |
|
(206) |
|
|
(194) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sales of investment securities held in trusts |
|
27 |
|
|
13 |
|
|
|
|
|
| Purchases of investment securities held in trusts |
|
(30) |
|
|
(16) |
|
|
|
|
|
| Asset removal costs |
|
(17) |
|
|
(18) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net cash used for investing activities |
|
(226) |
|
|
(215) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
| New financing- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Short-term borrowings - affiliated companies, net |
|
54 |
|
|
192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Redemptions and repayments- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Short-term borrowings - other, net |
|
— |
|
|
(200) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Equity contribution from parent |
|
— |
|
|
140 |
|
|
|
|
|
| Common stock dividend payments |
|
(30) |
|
|
— |
|
|
|
|
|
| Other |
|
(3) |
|
|
— |
|
|
|
|
|
| Net cash provided from financing activities |
|
21 |
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net change in cash, cash equivalents, and restricted cash |
|
— |
|
|
— |
|
|
|
|
|
| Cash, cash equivalents, and restricted cash at beginning of period |
|
— |
|
|
— |
|
|
|
|
|
| Cash, cash equivalents, and restricted cash at end of period |
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SUPPLEMENTAL CASH FLOW INFORMATION: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Significant non-cash transactions |
|
|
|
|
|
|
|
|
| Accrued capital investments |
|
$ |
79 |
|
|
$ |
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Combined Notes to Financial Statements of the Registrants.
COMBINED NOTES TO FINANCIAL STATEMENTS OF THE REGISTRANTS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Note |
|
|
Registrant |
|
Page
Number
|
|
|
|
|
|
|
|
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
2 |
Revenue |
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy |
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
| 8 |
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
| 9 |
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
| 10 |
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
| 11 |
|
|
FirstEnergy, JCP&L |
|
|
|
|
|
|
|
|
| 12 |
Transactions with Affiliates |
|
JCP&L |
|
|
1. ORGANIZATION AND BASIS OF PRESENTATION
Defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. Unless otherwise indicated, the disclosures in these notes apply to each of the Registrants. For clarification purposes, disclosures made herein on behalf of FirstEnergy should be read to be made on behalf of JCP&L unless expressly stated otherwise.
FirstEnergy
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: OE, CEI, TE, FE PA, JCP&L, FESC, MP, AGC (a wholly owned subsidiary of MP), PE and KATCo. Additionally, FET is a VIE of FE, and is the parent company of ATSI, MAIT, PATH and TrAIL. In March 2024, PATH completed the process of terminating all of its FERC-jurisdictional rates and facilities, with the result that PATH no longer is a “public utility” and no longer is subject to FERC jurisdiction. FET and its non-affiliated joint venture partner are completing the process of terminating the PATH corporate entities. FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s electric operating companies comprise one of the nation’s largest investor-owned electric systems, serving over 6 million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include more than 24,000 miles of lines and two regional transmission operation centers. As of March 31, 2025, AGC and MP control 3,604 MWs of net maximum generation capacity.
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.
FESC provides legal, financial and other corporate support services at cost, in accordance with its cost allocation manual, to affiliated FirstEnergy companies. FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries for services received from FESC either through direct billing or through an allocation process. Allocated costs are for services that are provided on behalf of more than one company and are allocated using formulas developed by FESC and are generally settled under commercial terms within thirty days.
On July 26, 2024, FE, VEPCO and Transource Energy, LLC, a subsidiary of AEP, entered into a joint proposal agreement in connection with PJM’s 2024 Regional Transmission Expansion Plan Open Window 1 process. Pursuant to such joint proposal agreement, FET, VEPCO and Transource Energy, LLC jointly proposed certain regional electric transmission projects for PJM's consideration during the Open Window process. On November 25, 2024, FET, Dominion High Voltage MidAtlantic, Inc., an affiliate of VEPCO, and Transource Energy, LLC, formed Valley Link, which is the holding company responsible for managing and executing any projects awarded by PJM, and entered into a limited liability agreement. On February 26, 2025, PJM selected certain of the joint proposed projects, which included approximately $3 billion in investments for Valley Link to both build new and upgrade existing transmission infrastructure.
JCP&L
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. JCP&L serves an area that has a population of approximately 2.8 million. JCP&L plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, JCP&L complies with the regulations, orders, policies and practices prescribed by FERC and the NJBPU.
Basis of Presentation
The Registrants follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements as of March 31, 2025, and the three months ended March 31, 2025 and 2024 are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The balance sheets, as of December 31, 2024, were derived from audited financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period.
The Registrants have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with FirstEnergy’s audited financial statements and notes included in its Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 27, 2025, and JCP&L’s Form S-4 filed with the SEC on April 1, 2025, respectively.
The Registrants 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. The Registrants consolidate a variable interest entity when it is determined that it is the primary beneficiary. Investments in affiliates over which the Registrants have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment on the Balance Sheets and the percentage of ownership share of the entity’s earnings is reported in the Statements of Income and Comprehensive Income.
Certain prior year amounts have been reclassified to conform to the current year presentation.
Economic Conditions
While supply lead times have not fully returned to pre-pandemic levels, FirstEnergy continues to monitor the situation in light of demand increases across the industry, including due to data center usage, and uncertainty around the imposition of tariffs by the U.S. government and retaliatory tariffs that have been, and may be, imposed in response. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, the situation remains fluid and a prolonged continuation or further increase in demand, or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
The U.S. presidential administration has announced the imposition of widespread and substantial tariffs on imports, with additional tariffs to potentially be adopted in the future. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
Capitalized Financing Costs
FirstEnergy - For the three months ended March 31, 2025 and 2024, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income and Comprehensive Income include $22 million and $13 million, respectively, of allowance for equity funds used during construction and $16 million and $17 million, respectively, of capitalized interest.
JCP&L - For the three months ended March 31, 2025 and 2024, capitalized financing costs on JCP&L’s Statements of Income and Comprehensive Income include $6 million and $1 million, respectively, of allowance for equity funds used during construction and $3 million and $6 million, respectively, of capitalized interest.
Reorganization
On March 24, 2025, FirstEnergy internally announced organizational changes to FirstEnergy employees. These organizational changes are intended to align FirstEnergy’s organization with its new business model, which is designed to make FE more efficient and sustainable while placing responsibility and accountability closer to customers, employees and regulators. The changes are also consistent with FirstEnergy’s focus on operations and maintenance expense discipline. These organizational changes resulted in approximately two hundred employees being reassigned and FirstEnergy reducing its workforce by less than three percent. As a result, FirstEnergy recognized a pre-tax charge of approximately $26 million ($5 million at JCP&L) during the first quarter of 2025, which is included within “Other operating expenses” on each of the Registrant’s Statements of Income and Comprehensive Income.
FET Noncontrolling Interest
FirstEnergy presents Brookfield’s 49.9% total ownership portion of FET’s net income and net assets as NCI. NCI is included as a component of equity on FirstEnergy’s Consolidated Balance Sheets.
Equity Method Investments
Investments over which the Registrants 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 in “Investments” on the Balance Sheets. The percentage of ownership share of the entity’s earnings is reported in the Statements of Income and Comprehensive Income and reflected in “Other income (expense)”.
Equity method investments, which are included within "Investments" on the FirstEnergy Consolidated Balance Sheets, were approximately $85 million and $84 million as of March 31, 2025, and December 31, 2024, respectively. JCP&L did not have any equity method investments as of March 31, 2025, or December 31, 2024.
Global Holding - FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales primarily focused on international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture’s economic performance. FEV's ownership interest is subject to the equity method of accounting. No income related to FEV’s ownership in Global Holding was recognized for the three months ended March 31, 2025. For the three months ended March 31, 2024, pre-tax income related to FEV’s ownership in Global Holding was $21 million. FEV’s pre-tax equity earnings and investment in Global Holding are included in Corporate/Other for segment reporting. FirstEnergy intends to exit from FEV’s equity method investment in Global Holdings.
As of March 31, 2025, and December 31, 2024, the carrying value of the equity method investment was $45 million.
Valley Link - On November 25, 2024, FET, Dominion High Voltage MidAtlantic, Inc., an affiliate of VEPCO, and Transource Energy, LLC, formed Valley Link, which is the holding company responsible for managing and executing any projects awarded by PJM, and entered into a limited liability agreement. On February 21, 2025, FET, Dominion HV and Transource entered into the Valley Link LLCA, which amended and restated a provisional operating agreement among the members entered into in November 2024. The Valley Link LLCA establishes the general framework for managing Valley Link, which was formed by FET, Dominion HV, and Transource to accept, design, develop, construct, own, operate and finance the transmission projects awarded by PJM to Valley Link on February 26, 2025, in response to the PJM 2024 Regional Transmission Expansion Plan Long-Term Proposal Window #1. This general framework includes the relationship among the members, confers governance rights to its members so long as certain ownership percentages are maintained, as described below, and defines the list of projects that Valley Link will have the right to develop. Valley Link is the owner of the Valley Link Subsidiaries, which are organized in various states. The Valley Link Subsidiaries comprise the entities that are expected to develop, construct, own, operate and maintain the transmission projects awarded by PJM. As of February 21, 2025, the relative ownership interests of the members are FET (34%), Dominion HV (30%), and Transource (36%), and Valley Link will not be consolidated with FET for financial or tax reporting purposes and expects to be accounted for under equity method accounting. As of March 31, 2025, and December 31, 2024, there were no investment balances recorded on the FirstEnergy Balance Sheets.
On February 26, 2025, PJM awarded two electric transmission projects to Valley Link, including the construction of (i) approximately 260 miles of 765-kilovolt (kV) transmission line and two substations between Putnam County, West Virginia and Frederick County, Maryland; (ii) approximately 155 miles of 765-kV transmission line and a substation between Campbell County, Virginia and Fauquier County, Virginia; and (iii) a new substation in Caroline County, Virginia. The total cost of these projects is estimated to be approximately $3.0 billion with FET’s estimated share will be approximately $1.020 billion.
PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland, which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of March 31, 2025 and December 31, 2024, the carrying value of the equity method investment was $17 million.
In March 2024, PATH completed the process of terminating all of its FERC-jurisdictional rates and facilities, with the result that PATH no longer is a “public utility” and no longer is subject to FERC jurisdiction. FirstEnergy and its non-affiliated joint venture partner are completing the process of terminating the PATH corporate entities.
New Accounting Pronouncements
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, the Registrants’ management 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. Management has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact the Registrants’ financial statements.
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. Disclosure requirements include a tabular reconciliation using both percentages and amounts, separated out into specific categories with certain reconciling items at or above 5% of the statutory tax as well as by nature and/or jurisdiction. In addition, entities will be required to disclose income taxes paid (net of refunds received), broken out between federal, state/local and foreign, and amounts paid to an individual jurisdiction when 5% or more of the total income taxes are paid to such jurisdiction. For the Registrants’, 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.
ASU 2024-03, "Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40)" (Issued in November 2024 and subsequently updated within ASU 2025-01): ASU 2024-03 requires disaggregated disclosure of income statement expenses for public business entities.
The ASU does not change the expense captions an entity presents on the face of the income statement; rather, it requires disaggregation of certain expense captions into specified categories in disclosures within the footnotes to the financial statements. ASU 2024-03 is effective for the Registrants for the first annual reporting period beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. The guidance is permitted to be applied prospectively, and comparative disclosures are not required for reporting periods beginning before the effective date. Entities can elect to apply the new standard retrospectively to any or all prior periods presented in the financial statements.
2. REVENUE
The disclosures in this note apply to both Registrants, unless indicated otherwise.
The following represents a disaggregation of FirstEnergy’s revenue from contracts with customers for the three months ended March 31, 2025 and 2024:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31 |
|
|
|
|
2025 |
|
2024 |
|
|
|
|
|
|
(In millions) |
|
|
|
|
| Distribution |
|
|
|
|
|
|
|
|
| Retail generation and distribution services: |
|
|
|
|
|
|
|
|
| Residential |
|
$ |
1,309 |
|
|
$ |
1,184 |
|
|
|
|
|
| Commercial |
|
415 |
|
|
374 |
|
|
|
|
|
| Industrial |
|
152 |
|
|
146 |
|
|
|
|
|
| Other |
|
19 |
|
|
20 |
|
|
|
|
|
| Wholesale |
|
1 |
|
|
1 |
|
|
|
|
|
| Other revenue from contracts with customers |
|
17 |
|
|
21 |
|
|
|
|
| Total revenues from contracts with customers |
|
1,913 |
|
|
1,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other revenue unrelated to contracts with customers |
|
23 |
|
|
21 |
|
|
|
|
| Total Distribution |
|
$ |
1,936 |
|
|
$ |
1,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Integrated |
|
|
|
|
|
|
|
|
| Retail generation and distribution services: |
|
|
|
|
|
|
|
|
| Residential |
|
$ |
708 |
|
|
$ |
574 |
|
|
|
|
|
| Commercial |
|
318 |
|
|
252 |
|
|
|
|
|
| Industrial |
|
151 |
|
|
138 |
|
|
|
|
|
| Other |
|
9 |
|
|
7 |
|
|
|
|
|
| Wholesale |
|
47 |
|
|
30 |
|
|
|
|
|
| Transmission |
|
100 |
|
|
81 |
|
|
|
|
| Other revenue from contracts with customers |
|
1 |
|
|
5 |
|
|
|
|
|
| Total revenues from contracts with customers |
|
1,334 |
|
|
1,087 |
|
|
|
|
|
| Other revenue unrelated to contracts with customers |
|
15 |
|
|
8 |
|
|
|
|
| Total Integrated |
|
$ |
1,349 |
|
|
$ |
1,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Stand-Alone Transmission |
|
|
|
|
|
|
|
|
| ATSI |
|
$ |
262 |
|
|
$ |
243 |
|
|
|
|
|
| TrAIL |
|
70 |
|
|
67 |
|
|
|
|
|
| MAIT |
|
131 |
|
|
104 |
|
|
|
|
|
| KATCo |
|
23 |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total revenues from contracts with customers |
|
486 |
|
|
434 |
|
|
|
|
|
| Other revenue unrelated to contracts with customers |
|
5 |
|
|
4 |
|
|
|
|
|
| Total Stand-Alone Transmission |
|
$ |
491 |
|
|
$ |
438 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate/Other, Eliminations and Reconciling Adjustments (1) |
|
|
|
|
|
|
|
|
| Wholesale |
|
$ |
4 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Eliminations and reconciling adjustments |
|
(15) |
|
|
(16) |
|
|
|
|
|
| Total Corporate/Other, Eliminations and Reconciling Adjustments |
|
$ |
(11) |
|
|
$ |
(13) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FirstEnergy Total Revenues |
|
$ |
3,765 |
|
|
$ |
3,287 |
|
|
|
|
|
(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
The following table represents a disaggregation of JCP&L’s revenue from contracts with customers for the three months ended March 31, 2025 and 2024:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31 |
|
2025 |
|
2024 |
|
(In millions) |
| Distribution |
|
|
|
| Retail generation and distribution services: |
|
|
|
| Residential |
$ |
343 |
|
|
$ |
286 |
|
| Commercial |
175 |
|
|
137 |
|
| Industrial |
20 |
|
|
17 |
|
Street lighting |
5 |
|
|
4 |
|
| Wholesale |
1 |
|
|
2 |
|
| Other revenue from contracts with customers |
3 |
|
|
5 |
|
| Total revenues from contracts with customers |
547 |
|
|
451 |
|
|
|
|
|
| Other revenue unrelated to contracts with customers |
1 |
|
|
1 |
|
| Total Distribution Segment Revenue |
$ |
548 |
|
|
$ |
452 |
|
|
|
|
|
| Transmission |
|
|
|
| Total Transmission Segment Revenue |
$ |
61 |
|
|
$ |
52 |
|
|
|
|
|
Reconciling Adjustments(1) |
|
|
|
| Retail generation and distribution services |
$ |
(43) |
|
|
$ |
(38) |
|
|
|
|
|
| JCP&L Total Revenues |
$ |
566 |
|
|
$ |
466 |
|
(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
Customer Receivables
Receivables from contracts with customers include distribution services and retail generation sales to residential, commercial and industrial customers. Billed and unbilled customer receivables as of March 31, 2025, and December 31, 2024, are included below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Customer Receivables - FirstEnergy |
|
March 31, 2025 |
|
December 31, 2024 |
|
| |
|
(In millions) |
| Billed |
|
$ |
1,024 |
|
|
$ |
867 |
|
|
| Unbilled |
|
600 |
|
|
718 |
|
|
|
|
1,624 |
|
|
1,585 |
|
|
| Less: Uncollectible Reserve |
|
50 |
|
|
55 |
|
|
| Total FirstEnergy Customer Receivables |
|
$ |
1,574 |
|
|
$ |
1,530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Customer Receivables - JCP&L |
|
March 31, 2025 |
|
December 31, 2024 |
| |
|
(In millions) |
| Billed |
|
$ |
163 |
|
|
$ |
166 |
|
| Unbilled |
|
99 |
|
|
118 |
|
|
|
262 |
|
|
284 |
|
| Less: Uncollectible Reserve |
|
5 |
|
|
6 |
|
| Total JCP&L Customer Receivables |
|
$ |
257 |
|
|
$ |
278 |
|
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.
The Registrants’ review allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Electric Companies are able to utilize to ensure payment. The Registrants’ uncollectible risk on PJM receivables, resulting from transmission and wholesale sales, is minimal due to the nature of PJM’s settlement process and as a result there is no current allowance for doubtful accounts.
Activity in the allowance for uncollectible accounts on customer receivables for the three months ended March 31, 2025, and for the year ended December 31, 2024 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy |
|
JCP&L |
|
|
|
|
|
|
|
(In millions) |
Balance, January 1, 2024 |
|
$ |
64 |
|
|
$ |
9 |
|
Provision for expected credit losses(1)(2) |
|
73 |
|
|
5 |
|
Charged to other accounts(3) |
|
39 |
|
|
4 |
|
| Write-offs |
|
(121) |
|
|
(12) |
|
Balance, December 31, 2024 |
|
$ |
55 |
|
|
$ |
6 |
|
Provision for expected credit losses(1)(2) |
|
24 |
|
|
1 |
|
Charged to other accounts(3) |
|
9 |
|
|
1 |
|
| Write-offs |
|
(38) |
|
|
(3) |
|
Balance, March 31, 2025 |
|
$ |
50 |
|
|
$ |
5 |
|
(1) Approximately $6 million and $17 million of which was deferred for future recovery for FirstEnergy in the three months ended March 31, 2025, and the year ended December 31, 2024, respectively.
(2) Approximately $1 million and $5 million of which was deferred for future recovery for JCP&L in the three months ended March 31, 2025, and the year ended December 31, 2024, respectively.
(3) Represents recoveries and reinstatements of accounts written off for uncollectible accounts.
3. EARNINGS PER SHARE OF COMMON STOCK
The disclosures in this note apply to FirstEnergy only.
EPS is calculated by dividing earnings attributable to FE by the weighted average number of common shares outstanding.
Basic EPS is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.
Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible securities. The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the 2026 Convertible Notes is computed using the if-converted method.
The following table reconciles basic and diluted EPS attributable to FE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
|
|
|
| Reconciliation of Basic and Diluted EPS |
|
2025 |
|
2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Earnings Attributable to FE |
|
$ |
360 |
|
|
$ |
253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Share count information: |
|
|
|
|
|
|
|
|
|
| Weighted average number of basic shares outstanding |
|
577 |
|
|
574 |
|
|
|
|
|
|
| Assumed exercise of dilutive share-based awards |
|
1 |
|
|
2 |
|
|
|
|
|
|
| Weighted average number of diluted shares outstanding |
|
578 |
|
|
576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| EPS Attributable to FE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Basic EPS |
|
$ |
0.62 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Diluted EPS |
|
$ |
0.62 |
|
|
$ |
0.44 |
|
|
|
|
|
|
For the three months ended March 31, 2025 and 2024, no shares from awards were excluded from the calculation of diluted shares outstanding, as their inclusion would have been antidilutive.
The dilutive effect of the 2026 Convertible Notes is limited to the conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted. For the three months ended March 31, 2025 and 2024, there was no dilutive effect resulting from the 2026 Convertible Notes as the average market price of FE shares of common stock was below the initial conversion price of $46.81 per share.
4. PENSION AND OTHER POST-EMPLOYMENT BENEFITS
The disclosures in this note apply to both Registrants, unless indicated otherwise.
FirstEnergy provides qualified benefit plans, through the FirstEnergy Master Pension Plan and the FirstEnergy Welfare Plan that cover substantially all employees and non-qualified defined benefit plans that cover certain employees, including employees of JCP&L. FirstEnergy’s pension and OPEB plans are neither multiemployer nor multiple-employer plans.
The Registrants recognize 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.
FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027, which, based on various assumptions, including an expected rate of return on assets of 8.5% for 2025, is expected to be approximately $300 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily. JCP&L is not expected to make a contribution.
In January 2025, FirstEnergy executed a lift-out transaction with MetLife, which transferred approximately $640 million of plan assets and $652 million of plan obligations, associated with approximately 2,000 former competitive generation employees, who will assume future and full responsibility to fund and administer their benefit payments. There was no change to the pension benefits for any participant as a result of the transfer and the transaction was funded by pension plan assets. FirstEnergy believes that this lift-out transaction, in addition to the lift-out in 2023, further de-risked potential volatility with the pension plan assets and liabilities, and will continue to evaluate other lift-outs in the future based on market and other conditions. Due to the timing of the lift-out transaction and its proximity to the 2024 annual remeasurement, FirstEnergy elected a practical expedient and did not remeasure pension plan assets and obligations when the lift-out occurred in January 2025.
Service costs, net of capitalization, are reported within “Other operating expenses” on the Registrants’ Statements of Income and Comprehensive 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 the Registrants’ Statements of Income and Comprehensive Income.
FirstEnergy cash flows from operating activities for the three months ended March 31, 2025 and 2024, includes approximately $12 million and $20 million, respectively, of employee benefit plan funding and related payments. These payments are primarily related to short-term benefit payment liabilities owed to retirees under plan obligations in the respective periods.
The components of FirstEnergy’s net periodic benefit costs (credits) for pension and OPEB were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FirstEnergy Components of Net Periodic Benefit Costs (Credits) |
|
Pension |
OPEB |
| For the Three Months Ended March 31, |
|
2025 |
|
2024 |
|
2025 |
|
2024 |
| |
|
(In millions) |
| Service costs |
|
$ |
33 |
|
|
$ |
35 |
|
|
$ |
1 |
|
|
$ |
1 |
|
| Interest costs |
|
93 |
|
|
99 |
|
|
5 |
|
|
5 |
|
| Expected return on plan assets |
|
(115) |
|
|
(133) |
|
|
$ |
(10) |
|
|
(8) |
|
| Amortization of prior service costs (credits) |
|
— |
|
|
1 |
|
|
— |
|
|
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net periodic benefit costs (credits) |
|
$ |
11 |
|
|
$ |
2 |
|
|
$ |
(4) |
|
|
$ |
(3) |
|
| Net periodic benefit credits, net of amounts capitalized |
|
$ |
(6) |
|
|
$ |
(15) |
|
|
$ |
(4) |
|
|
$ |
(4) |
|
|
|
|
|
|
|
|
|
|
JCP&L
JCP&L recognizes its allocated portion of 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. JCP&L also recognizes its allocated portion of obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
JCP&L cash flows from operating activities for the three months ended March 31, 2024, includes approximately $7 million of employee benefit plan funding and related payments. These payments are primarily related to short-term benefit payment liabilities owed to retirees under plan obligations in the respective periods.
JCP&L’s net periodic benefit costs (credits) for pension and OPEB were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension |
|
OPEB |
| For the Three Months Ended March 31, |
|
2025 |
|
2024 |
|
2025 |
|
2024 |
|
(In millions) |
JCP&L's share of net periodic benefit credits(1) |
|
$ |
(1) |
|
|
$ |
(1) |
|
|
$ |
(4) |
|
|
$ |
(3) |
|
(1) Includes amounts capitalized
In addition to the net periodic benefit costs for its current and former employees and retirees, JCP&L is also allocated pension and OPEB net periodic benefit costs and credits from its affiliates, primarily FESC. JCP&L was allocated from affiliates $2 million of net periodic pension costs for both the three months ended March 31, 2025 and 2024. Net periodic OPEB costs allocated from affiliates for the three months ended March 31, 2025 and 2024, were immaterial.
5. INCOME TAXES
The disclosures in this note apply to both Registrants, unless indicated otherwise.
The Registrants’ interim effective income tax rates reflect the estimated annual effective income tax rates for 2025 and 2024. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as certain discrete items.
The following table reconciles the FirstEnergy effective income tax rate to the federal income tax statutory rate for the three months ended March 31, 2025 and 2024:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FirstEnergy |
|
For the Three Months Ended March 31, |
|
|
|
|
2025 |
|
2024 |
|
|
|
|
|
|
(In millions) |
| Income before income taxes |
|
$ |
540 |
|
|
$ |
402 |
|
|
|
|
|
| Federal income tax expense at the 21% statutory rate |
|
$ |
113 |
|
|
$ |
84 |
|
|
|
|
|
| Increases (reductions) in tax expense resulting from: |
|
|
|
|
|
|
|
|
| State and municipal income taxes, net of federal tax benefit |
|
31 |
|
|
23 |
|
|
|
|
|
| AFUDC equity and other flow-through |
|
(9) |
|
|
(7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes related to the combined sale of 49.9% of the equity interests of FET |
|
— |
|
|
7 |
|
|
|
|
|
| Excess deferred tax amortization |
|
(13) |
|
|
(13) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Valuation allowances |
|
— |
|
|
39 |
|
|
|
|
|
| Other, net |
|
4 |
|
|
2 |
|
|
|
|
|
| Total income taxes |
|
$ |
126 |
|
|
$ |
135 |
|
|
|
|
|
| Effective income tax rate |
|
23.3 |
% |
|
33.6 |
% |
|
|
|
|
The following table reconciles the JCP&L effective income tax rate to the federal income tax statutory rate for the three months ended March 31, 2025 and 2024:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| JCP&L |
|
For the Three Months Ended March 31, |
|
|
2025 |
|
2024 |
|
|
(In millions) |
| Income (loss) before income taxes (benefits) |
|
$ |
65 |
|
|
$ |
(12) |
|
| Federal income tax expense (benefit) at the 21% statutory rate |
|
$ |
14 |
|
|
$ |
(3) |
|
| Increases (reductions) in tax expense resulting from: |
|
|
|
|
| State income taxes, net of federal tax benefit |
|
5 |
|
|
(1) |
|
| AFUDC equity and other flow-through |
|
(2) |
|
|
— |
|
| Excess deferred tax amortization |
|
(1) |
|
|
(1) |
|
|
|
|
|
|
| Other, net |
|
— |
|
|
1 |
|
| Total income taxes (benefits) |
|
$ |
16 |
|
|
$ |
(4) |
|
| Effective income tax rate |
|
24.6 |
% |
|
33.3 |
% |
The IRA of 2022, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. The IRA of 2022 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. On September 12, 2024, the U.S. Treasury issued proposed regulations for the AMT for comments. FirstEnergy is assessing the proposed regulations but continues to believe that it is more likely than not that it will be subject to AMT, however, the completion of the U.S. Treasury’s rulemaking process and the future issuance of final regulations, as well as potential future federal tax legislation or presidential executive orders, could significantly change FirstEnergy’s AMT estimates or its conclusion as to whether it is an AMT payer at all. JCP&L is party to an intercompany income tax allocation agreement with FirstEnergy and, accordingly, may be allocated a share of any AMT paid by the FirstEnergy consolidated group. As further discussed below, FirstEnergy expects to pay regular federal corporate income tax for the 2024 tax year, due in large part to the gain realized from closing the FET Equity Interest Sale. The regulatory treatment of the IRA of 2022 may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in the IRA of 2022, 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, on March 25, 2024, FirstEnergy closed on the FET Equity Interest Sale realizing an approximate $7 billion tax gain from the combined sale of 49.9% of the equity 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 available to offset a majority of the tax gain and taxable income in 2024. Due to certain limitations on NOL utilization enacted in the Tax Act, approximately $1.6 billion NOL is carrying forward into 2025 and possibly beyond. In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% FET equity interest sale in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA consolidation, and recognized a reduction to OPIC of approximately $803 million for federal and state income tax associated with the tax gain from closing on the FET Equity Interest Sale.
6. FAIR VALUE MEASUREMENTS
The disclosures in this note apply to both Registrants, unless indicated otherwise.
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.
The Registrants primarily apply the market approach for recurring fair value measurements using the best information available. Accordingly, the Registrants, maximize the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2025, from those used as of December 31, 2024. 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.
The following table sets forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2025 |
|
December 31, 2024 |
| FirstEnergy |
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
| Assets |
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets FTRs(1) |
$ |
— |
|
|
$ |
— |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
7 |
|
|
$ |
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Equity securities |
2 |
|
|
— |
|
|
— |
|
|
2 |
|
|
2 |
|
|
— |
|
|
— |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities(2) |
— |
|
|
272 |
|
|
— |
|
|
272 |
|
|
— |
|
|
276 |
|
|
— |
|
|
276 |
|
Cash, cash equivalents and restricted cash(3) |
163 |
|
|
— |
|
|
— |
|
|
163 |
|
|
154 |
|
|
— |
|
|
— |
|
|
154 |
|
Other(4) |
— |
|
|
52 |
|
|
— |
|
|
52 |
|
|
— |
|
|
45 |
|
|
— |
|
|
45 |
|
| Total assets |
$ |
165 |
|
|
$ |
324 |
|
|
$ |
1 |
|
|
$ |
490 |
|
|
$ |
156 |
|
|
$ |
321 |
|
|
$ |
7 |
|
|
$ |
484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities FTRs(1) |
$ |
— |
|
|
$ |
— |
|
|
$ |
(1) |
|
|
$ |
(1) |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities |
$ |
— |
|
|
$ |
— |
|
|
$ |
(1) |
|
|
$ |
(1) |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net assets |
$ |
165 |
|
|
$ |
324 |
|
|
$ |
— |
|
|
$ |
489 |
|
|
$ |
156 |
|
|
$ |
321 |
|
|
$ |
7 |
|
|
$ |
484 |
|
(1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.
(2) Related to JCP&L’s investments held in the spent nuclear fuel disposal trusts, see below.
(2) Restricted cash of $31 million and $43 million as of March 31, 2025, and December 31, 2024, respectively, primarily relates to cash collected from MP, PE and the Ohio Companies’ customers that is specifically used to service debt of their respective securitization or funding companies.
(4) Primarily consists of short-term investments, of which $11 million and $6 million as of March 31, 2025, and December 31, 2024, respectively, are held by JCP&L.
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. The Registrants have 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 DOE associated with the previously owned Oyster Creek and Three Mile Island Unit 1 nuclear power plants.
The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in spent nuclear fuel disposal trusts as of March 31, 2025, and December 31, 2024:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2025(1) |
|
December 31, 2024(2) |
|
|
Cost Basis |
|
Unrealized Gains |
|
Unrealized Losses |
|
Fair Value |
|
Cost Basis |
|
Unrealized Gains |
|
Unrealized Losses |
|
Fair Value |
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Debt securities |
|
$ |
295 |
|
|
$ |
— |
|
|
$ |
(23) |
|
|
$ |
272 |
|
|
$ |
299 |
|
|
$ |
— |
|
|
$ |
(23) |
|
|
$ |
276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Excludes short-term cash investments of $11 million as of March 31, 2025.
(2) Excludes short-term cash investments of $6 million as of December 31, 2024.
Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three months ended March 31, 2025 and 2024, were as follows for the Registrants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
|
|
|
|
2025 |
|
2024 |
|
|
|
|
|
|
(In millions) |
| Sale proceeds |
|
$ |
27 |
|
|
13 |
|
|
|
|
|
| Realized gains |
|
— |
|
|
— |
|
|
|
|
|
| Realized losses |
|
(2) |
|
|
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
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| Interest and dividend income |
|
3 |
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|
3 |
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|
|
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 “Miscellaneous Income, net” line on FirstEnergy’s Consolidated Statements of Income. Other investments were $374 million and $370 million as of March 31, 2025, and December 31, 2024, respectively, and are excluded from the amounts reported above. See Note 1, "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants for additional information on FirstEnergy's equity method investments.
For the three months ended March 31, 2025 and 2024, pre-tax income related to corporate-owned life insurance policies was $2 million and $9 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, the Registrants believe 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 March 31, 2025, and December 31, 2024:
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| FirstEnergy |
|
March 31, 2025 |
|
December 31, 2024 |
|
|
(In millions) |
| Carrying value |
|
$ |
23,270 |
|
|
$ |
23,594 |
|
| Fair value |
|
$ |
22,097 |
|
|
$ |
22,128 |
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| JCP&L |
|
March 31, 2025 |
|
December 31, 2024 |
|
|
(In millions) |
| Carrying value |
|
$ |
2,350 |
|
|
2,350 |
|
| Fair value |
|
$ |
2,308 |
|
|
2,284 |
|
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 the Registrants. The Registrants classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of March 31, 2025, and December 31, 2024.
FirstEnergy had the following issuances and redemptions during the three months ended March 31, 2025 (JCP&L had no issuances or redemptions):
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| Company |
Type |
Redemption / Issuance Date |
Interest Rate |
Maturity |
Amount
(In millions)
|
Description |
| Redemptions |
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|
|
| FE |
Unsecured Notes |
March, 2025 |
2.050% |
2025 |
$300 |
FE redeemed unsecured notes that became due. |
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On April 16, 2025, TrAIL issued $600 million of senior notes due 2031 at 5.00%. Proceeds are expected to be used to redeem senior notes that will be coming due in 2025 and repay short-term borrowings, as well as to fund capital investments, working capital and other corporate purposes.
On December 5, 2024, JCP&L issued $700 million of unsecured senior notes due in 2035 in a private offering that included a registration rights agreement in which JCP&L agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act. On April 1, 2025, JCP&L filed a registration statement on Form S-4 with the SEC, which became effective on April 11, 2025.
7. VARIABLE INTEREST ENTITIES
The disclosures in this note apply to both Registrants, unless indicated otherwise.
The Registrants perform qualitative analyses to determine whether a variable interest qualifies them as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The Registrants consolidate 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 $12 billion of consolidated VIE assets, as of March 31, 2025, and December 31, 2024, that can only be used to settle the liabilities of the applicable VIE. Total liabilities include approximately $9 billion as of March 31, 2025, and December 31, 2024, of consolidated VIE liabilities for which the VIE's creditors do not have recourse to FirstEnergy. JCP&L does not have any consolidated VIE’s.
VIEs in which FirstEnergy is the primary beneficiary consist of the following, and are included in FirstEnergy’s consolidated financial statements:
Securitization Companies
•Ohio Securitization Companies - In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. The SPEs are considered VIEs and each one is consolidated into its applicable electric company. As of March 31, 2025, and December 31, 2024, $167 million and $175 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 March 31, 2025, and December 31, 2024, $172 million and $188 million of environmental control bonds were outstanding, respectively.
Cash of $27 million and $40 million, respectively, as of March 31, 2025 and December 31, 2024 collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies is included in “Restricted cash” on the FirstEnergy Consolidated Balance Sheets.
FET
FET is a holding company that owns equity interests in ATSI, MAIT, TrAIL and PATH. As of March 31, 2025, FE’s equity ownership in FET is 50.1% and Brookfield’s is 49.9%. FirstEnergy has concluded that FET is a VIE and that FE is the primary beneficiary because FE has exposure to the economics of FET and the power to direct significant activities of FET through the FESC services agreement, which represents a separate variable interest.
Although Brookfield was granted incremental consent rights upon the closing of the FET Equity Interest Sale, Brookfield will not have unilateral control over any activities that most significantly impact FET’s economic performance. However, FE will continue to retain power over the activities that most significantly impact FET’s economic performance through its incremental decision-making rights under the existing FESC services agreement, through which executive management and workforce services are provided to FET. As a result, FE is the primary beneficiary of FET, which will continue to be consolidated in FirstEnergy’s financial statements.
The following shows the carrying amounts and classification of the FET assets and liabilities included in FirstEnergy’s consolidated financial statements as of March 31, 2025, and December 31, 2024. 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 FE.
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|
|
| Assets |
|
As of
March 31, 2025
|
|
As of December 31, 2024 |
|
|
(In millions) |
| Cash and cash equivalents |
|
$ |
7 |
|
|
$ |
8 |
|
| Receivables |
|
97 |
|
94 |
| Materials and supplies, at average cost |
|
1 |
|
|
1 |
|
| Prepaid taxes and other current assets |
|
20 |
|
|
21 |
|
| Total current assets |
|
125 |
|
|
124 |
|
| Property, plant and equipment, net |
|
11,422 |
|
|
11,217 |
|
| Goodwill |
|
224 |
|
|
224 |
|
| Investments |
|
19 |
|
|
19 |
|
| Regulatory assets |
|
24 |
|
|
18 |
|
| Other noncurrent assets |
|
257 |
|
|
334 |
|
| Total noncurrent assets |
|
11,946 |
|
|
11,812 |
|
| TOTAL ASSETS |
|
$ |
12,071 |
|
|
$ |
11,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Liabilities |
|
As of
March 31, 2025
|
|
As of
December 31, 2024
|
|
|
(In millions) |
|
|
|
|
|
| Currently payable long-term debt |
|
$ |
625 |
|
|
$ |
625 |
|
| Short-term borrowings |
|
385 |
|
|
300 |
|
|
|
|
|
|
| Accrued interest |
|
70 |
|
|
68 |
|
| Accrued taxes |
|
314 |
|
|
306 |
|
| Other current liabilities |
|
15 |
|
|
15 |
|
| Total current liabilities |
|
1,409 |
|
|
1,314 |
|
| Long-term debt and other long-term obligations |
|
5,240 |
|
|
5,239 |
|
| Accumulated deferred income taxes |
|
1,436 |
|
|
1,412 |
|
| Regulatory liabilities |
|
463 |
|
|
442 |
|
| Other noncurrent liabilities |
|
150 |
|
|
299 |
|
| Total noncurrent liabilities |
|
7,289 |
|
|
7,392 |
|
| TOTAL LIABILITIES |
|
$ |
8,698 |
|
|
$ |
8,706 |
|
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.
The Registrants evaluated their PPAs and determined that certain Non-Utility Generation entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. As of March 31, 2025, FirstEnergy maintains four, one at JCP&L, long-term PPAs with Non-Utility Generation entities that were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. The Registrants were not involved in the creation of, and have no equity or debt invested in, any of these entities. The Registrants have determined that they do not have a variable interest, or the entities do not meet the criteria to be considered a VIE.
Because the Registrants have no equity or debt interests in the Non-Utility Generation entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power, which are expected to be recovered from customers.
8. ASSET RETIREMENT OBLIGATIONS
The disclosures in this note apply to both Registrants, unless indicated otherwise.
The Registrants recognize an ARO for their legal obligation to perform asset retirement activities associated with their long-lived assets. The ARO liability represents an estimate of the fair value of the Registrants’ 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. An expected cash flow approach is used to measure the fair value of the remediation AROs, taking into account the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. For instances where asset retirement costs relate to assets that have no future cash flows, the costs are recorded as an operating expense. In certain circumstances, The Registrants have recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition.
FirstEnergy has recognized applicable legal obligations for AROs and their associated costs, including reclamation of sludge disposal ponds, closure of CCR sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, the Registrants have recognized conditional retirement obligations, primarily for asbestos remediation.
The following table summarizes the changes to the ARO balances as of March 31, 2025, and December 31, 2024
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|
|
FirstEnergy |
|
JCP&L |
|
|
(In millions) |
Balance, January 1, 2024 |
|
$ |
209 |
|
|
$ |
7 |
|
| Changes in timing and amount of estimated cash flows |
|
131 |
|
|
— |
|
| Liabilities incurred |
|
95 |
|
|
— |
|
| Liabilities settled |
|
(4) |
|
|
— |
|
| Accretion |
|
24 |
|
|
1 |
|
Balance, December 31, 2024 |
|
455 |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
Liabilities settled (1) |
|
(151) |
|
|
— |
|
| Accretion |
|
7 |
|
|
— |
|
Balance, March 31, 2025 |
|
$ |
311 |
|
|
$ |
8 |
|
(1) FirstEnergy amounts include the transfer of the McElroy’s Run CCR impoundment facility as well as the adjacent dry landfill and related remediation obligations to subsidiary of IDA Power, LLC.
During 2024, as a result of the evaluation of closure options for McElroy’s Run and the adjacent landfill, AE Supply reviewed its ARO and future expected costs to remediate, resulting in an increase to the ARO liability of $87 million. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025, with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. In connection with the transfer, AE Supply made a $15 million cash payment to the escrow account, recognized a $130 million liability, based on a 4.8% weighted average discount rate over the contract term, associated with its remaining obligation to fund the escrow account over the next five years, and derecognized the ARO, resulting in an immaterial impact to earnings.
As further discussed below, on May 8, 2024, the EPA finalized changes to the CCR rule addressing certain legacy CCR disposal sites that were not included in previous CCR rules. As a result, during 2024, FirstEnergy performed a preliminary assessment of former CCR disposal sites and calculated an initial estimate applying historical experience in remediating comparable sites and recorded a $139 million increase to its ARO in 2024. JCP&L did not have any legacy CCR disposal sites that were applicable to the new CCR rule.
The ARO increase related to certain legacy CCR disposal sites represents the discounted cash flows for estimated closure costs based upon the potential closure requirements as evaluated on a site-by-site basis. Actual costs to be incurred will be dependent upon factors that vary from site to site. The most significant factors include the method and time frame of closure at the individual sites, which will be determined based on the groundwater monitoring and, if applicable, EPA approval of closure plans. In determining the estimated closure costs for each site, FirstEnergy has assumed the anticipated applicable closure method, however, alternative closure methods may be required, resulting in greater or lesser cost. As a result, the ARO liability may be adjusted as additional information is gained through the evaluation and closure process, including further inspection of the sites, results of groundwater monitoring and changes in interpretation of the CCR regulations which may change management assumptions, and could result in a material change to the ARO liability balance and FirstEnergy’s results of operations.
9. REGULATORY MATTERS
The disclosures in this note apply to FirstEnergy, with the disclosures under “State Regulation”, “New Jersey”, “FERC Regulatory Matters”, “FERC Audit”, “Transmission ROE Methodology” and “Industrial Energy Consumers of America, et al. v. Avista Corporation, et al.” also applicable to JCP&L.
STATE REGULATION
Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
MARYLAND
PE operates under MDPSC approved distribution base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program, following passage of the Climate Solutions Now Act of 2022, required annual incremental energy efficiency targets of 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally, at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million, which the MDPSC approved on December 27, 2024. PE recovers EmPOWER Maryland program costs with carrying costs on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Lost distribution revenue attributable to energy efficiency or demand reduction is recovered only through base rates. Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 67% of its EmPOWER Maryland program costs in 2025, and 100% in 2026 and beyond. All previously unamortized costs for prior cycles are to be collected by the end of 2030, consistent with the 2024-2026 order issued on December 29, 2023. New legislation which took effect on July 1, 2024 is expected to reduce the carrying costs on the EmPOWER unamortized balances for PE by a total of $25 to $30 million over the period of 2024-2030. On July 31, 2024, the MDPSC issued an order implementing revised EmPOWER surcharge rates for PE in accordance with the new law, denying PE’s request for a hearing that sought to challenge certain portions of the law. On August 30, 2024, PE filed a petition seeking judicial review of its challenge to the law in the Circuit Court for Washington County, Maryland. Legal memoranda were filed in December 2024 through February 2025 and a hearing was held on March 7, 2025.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L and one other party filed comments on July 31, 2023.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. On January 30, 2025, and February 25, 2025, Shell New Energies and EDF Renewables North America respectively announced that each was exiting its Atlantic Shores partnership to construct wind energy off the shore of New Jersey. These cancellations do not directly affect JCP&L’s awarded projects, and JCP&L remains under an obligation to begin construction in 2025 based on current NJBPU direction. JCP&L continues to monitor the situation and is engaging state officials about impacts of these announcements to its transmission projects.
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 DOE to finance a substantial portion of the project using low-interest rate loans available under the DOE’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024, which was approved on May 17, 2024.
The DOE Loan Program Office has initiated a due diligence review of the application, which is ongoing. On January 16, 2025, the DOE announced a conditional commitment to JCP&L for a loan guarantee of up to approximately $716 million for the project. While this conditional commitment represents a significant milestone and demonstrates the DOE’s intent to finance the project, certain technical, legal, environmental and financial conditions, including negotiation of definitive financing documents, must be satisfied before funding of the loan.
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. On April 10, 2025, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s amended EnergizeNJ petition, which the NJBPU approved on April 23, 2025. The settlement provides for total program costs of $339 million, including capital investments in JCP&L’s electric distribution system of approximately $203 million, $132 million of matching capital investment and approximately $4 million of O&M expense. Pursuant to the settlement, the program would begin on July 1, 2025, and continue through December 31, 2028, and JCP&L has agreed to file a base rate case no later than January 1, 2030.
OHIO
The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. From June 1, 2024, until January 31, 2025, the Ohio Companies operated under ESP V, as modified by the PUCO, and as further described below. On December 18, 2024, the PUCO approved the Ohio Companies’ notice to withdraw ESP V and approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. ESP IV, as modified, continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with an annual revenue cap of $390 million. In addition, ESP IV, as modified, includes: (1) continuation of a base distribution rate freeze until ESP VI becomes effective or the Ohio Companies’ obtain the PUCO’s staff agreement; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $6.39 million per year to: (a) fund energy conservation, economic development and job retention programs in the Ohio Companies’ service territories; and (b) establish fuel-funds in each of the Ohio Companies’ service territories to assist low-income customers.
On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which became effective June 1, 2024, and would have continued through May 31, 2029. ESP V, as modified by the PUCO, provided for, among other things, the continuation of existing riders related to purchased power, transmission and uncollectibles, the continuation of the DCR rider with proposed annual revenue cap increases until new base rates are established, the continuation of the AMI rider, and the addition of new riders for recovery of storm and vegetation management expenses. Many of the terms and conditions were to be reconsidered in the base rate case. The ESP V order additionally directed the Ohio Companies to file another base distribution rate case not later than May 31, 2028, and contribute $32.5 million during the term of ESP V to fund low-income customer bill assistance programs and bill assistance for income-eligible senior citizens, and to develop an electric vehicle education program to assist customers in transitioning to electric vehicles which was recognized in the second quarter of 2024 within “Other operating expenses” at the Regulated Distribution segment and on FirstEnergy’s Consolidated Statements of Income. Due to the risks and uncertainty resulting from the Ohio Companies’ application for rehearing being denied by operation of law, on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. On December 18, 2024, the PUCO approved the Ohio Companies’ notice of withdrawal. Also on December 18, 2024, the PUCO approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. Consistent with ESP IV, the PUCO authorized the Ohio Companies’ reinstatement of the DCR rider, with an annual revenue cap of $390 million, and denied the Ohio Companies’ request to continue ESP IV’s DCR rider revenue cap increases of $15 million per year. Additionally, the PUCO ordered that storm costs deferred under ESP V since June 1, 2024, remain on the Ohio Companies’ books and subject to review in a future case. The PUCO also denied the Ohio Companies’ request to lift the base rate freeze in ESP IV, permitting the Ohio Companies’ pending base rate case to continue, but prohibiting new rates from going into effect until either the effective date of ESP VI, or the staff agrees that the freeze be lifted and new rates be implemented. On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV. On March 14, 2025, the Ohio Companies filed with the PUCO a request to commence its quadrennial review of ESP IV and establish the proposed schedule. The request remains pending before the PUCO. On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV.
On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI, for a term beginning on the date new base distribution rates from the pending base rate case go into effect, in an effort to align with the ongoing base distribution rate case, and continuing through May 31, 2028. ESP VI proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, and proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual reliability performance-based revenue cap increases of $37 million to $43 million, and an AMI rider for recovery of approved grid modernization investments. ESP VI additionally proposes riders to support continued maintenance of the distribution system, including recovery of vegetation management and storm restoration operations and maintenance expenses. In addition, ESP VI proposes energy efficiency programs for low-income customers, and includes a commitment to spend $6.5 million annually over the ESP VI term, without recovery from customers, on initiatives to assist low-income customers, as well as education and incentives to help ensure customers have good experiences with electric vehicles. The PUCO held a technical conference on March 12, 2025.
On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million, with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual amount each year using this method. Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony. On July 31, 2024, the Ohio Companies filed an update that adjusted the net increase in base distribution revenues to approximately $190 million and incorporated matters in the rate case as directed by the PUCO’s ESP V order. On January 27, 2025, the Ohio Companies filed a notice in the base rate case notifying parties that they will update their application for an increase in base distribution rates to reflect the withdrawal of ESP V and the reversion to ESP IV. The PUCO Staff hired a third-party to assist in the review of the Ohio Companies' base rate case filing, and on February 21, 2025, PUCO staff and the third party auditor each filed their reports. The auditor’s report recommended adjustments which would result in a net increase of the Ohio Companies’ base distribution revenues of approximately $8 million, with a return on equity of 9.63% and capital structures of 48.8% debt and 51.2% equity for each of the Ohio Companies. PUCO staff’s report takes limited positions on the auditor’s finding and recommendations and makes additional findings. On March 24, 2025, the Ohio Companies, OCC, and other parties filed objections to the PUCO’s staff report and the auditor’s report. In addition, the Ohio Companies filed certain pieces of supplemental testimony and intervenors filed direct testimony. The Ohio Companies and various parties are engaged in settlement discussions with respect to the pending base rate case. Evidentiary hearings are scheduled to begin May 5, 2025.
On May 16, 2022, May 15, 2023, and May 15, 2024, the Ohio Companies filed their SEET applications for determination of the existence of significantly excessive earnings under ESP IV for calendar years 2021, 2022, and 2023, respectively. Each application demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. These matters remain pending before the PUCO.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below and on November 22, 2024, the administrative law judge ordered that the bifurcated portion of the corporate separation audit, discussed further below, be consolidated with the already-consolidated DMR audit and expanded DCR rider audit proceeding. Evidentiary hearings are scheduled to begin June 10, 2025.
On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directed the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the DCR rider audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand.
On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and the stay was lifted on February 26, 2024. On September 30, 2024, the third-party auditor’s report was filed. The audit examined 53 payments totaling approximately $75 million made in support of the passage of HB 6 and subsequent referendum efforts, and concluded that less than $5 million was allocated to the Ohio Companies. The audit report affirmed the Ohio Companies’ conclusion in its August 6, 2021, filing that a rate impact of less than $15 thousand was charged to the Ohio Companies’ pole attachment customers associated with political and charitable spending in support of HB 6. On October 22, 2024, parties filed comments on the audit report, and on November 5, 2024, parties filed reply comments. The parties' comments remain pending with the PUCO.
In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and the stay was lifted on February 26, 2024. On September 10, 2024, the Ohio Companies filed testimony describing their compliance with Ohio corporate separation laws and the implementation of the recommendations made in the audit reports. On September 20, 2024, intervenors filed testimony recommending fines for alleged violations of the Ohio corporate separation requirements. Evidentiary hearings were held on October 9 and 10, 2024; the scope of the hearings excluded allegations involving activities related to the passage of HB 6 and the former PUCO chairman, which will be addressed at a later time. Initial and reply briefs have been filed by the Ohio Companies, PUCO staff and the intervening parties. To the extent the PUCO ultimately accepts the intervenors’ recommendations and issues a fine to the Ohio Companies, such amount is not expected to be material.
On September 3, 2024, the Ohio Companies filed an application to amend their corporate separation plan to incorporate certain recommendations from prior audit reports, which include, but are not limited to, improving controls for non-regulated competitive employees’ physical space and access to data, updating and implementing a process to annually review the cost allocation manual, developing state specific codes of conduct practices, and implementing additional training related to the cost allocation manual and the state codes of conduct. On October 23, 2024, the administrative law judge issued an entry suspending automatic approval of the amended corporate separation plan and establishing a procedural schedule.
In connection with an ongoing annual audit of the Ohio Companies’ DCR rider for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through the DCR rider or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and the stay was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, and further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement. On November 22, 2024, the administrative law judge ordered that the bifurcated portion of the corporate separation audit be consolidated with the already-consolidated DMR audit and the expanded DCR rider audit proceeding. Evidentiary hearings are scheduled to begin June 10, 2025.
On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023, entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans.
On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing. As the PUCO did not rule on OCC’s November 17, 2023, application for rehearing within 30 days of filing, the application for rehearing was denied by operation of law.
In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.
See Note 10, “Commitments, Guarantees and Contingencies” of the Combined Notes to Financial Statements of the Registrants below for additional details on the government investigations and ongoing litigation surrounding the investigation of HB 6.
PENNSYLVANIA
FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025. FE PA operates under rates approved by the PPUC, effective as of January 1, 2025.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.
Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for accelerated infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the 2025-2029 phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period. The PPUC approved FE PA’s application on December 19, 2024, and implementation began in January 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective March 27, 2024. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually and MP and PE will file their next ENEC filing on or before September 1, 2025, for rates effective January 1, 2026.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. 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, and two of the five solar generation sites went into service in 2024. On December 4, 2024, MP and PE submitted for approval a settlement agreement to increase its solar surcharge rate. The WVPSC approved the settlement without modification on December 27, 2024, and new rates went into effect on January 1, 2025.
FERC REGULATORY MATTERS
Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015, through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy 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 reclassified certain transmission capital assets to operating expenses for the audit period. FirstEnergy fully recovered approximately $105 million ($13 million at JCP&L) of these costs reclassified to operating expenses in its transmission formula rate revenue requirements as of December 31, 2024. Furthermore, the Ohio Companies are in the process of addressing the outcomes of the FERC Audit with the PUCO, which includes seeking continued rate base treatment of approximately $99 million of certain corporate support costs allocated to distribution capital assets as of March 31, 2025.
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. On July 5, 2024, and September 26, 2024, the FERC Office of Enforcement issued additional data requests related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. On September 10, 2024, and January 13, 2025, the FERC Office of Enforcement issued further data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy responded. If the FERC Office of Energy Market Regulation and the FERC Office of Enforcement were to successfully challenge the recovery of the 2022 reclassified operating expenses and formula transmission rates it could have material adverse effect on FirstEnergy financial conditions, result of operations, and cash flows.
Transmission ROE Incentive
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. On January 17, 2025, the Sixth Circuit ruled that the 50 basis point adder is available only where RTO membership is voluntary, that Ohio law requires Ohio’s transmission utilities to be members of an RTO, and that it was unlawful for FERC to excise the adder from AEP rates, but not from the Duke and ATSI rates. During 2024, as a result of the ruling, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the Consolidated Statements of Income and Comprehensive Income at the Stand-Alone Transmission segment, to reflect the expected refund owed to transmission customers back to February 24, 2022.
On March 3, 2025, FirstEnergy filed for rehearing en banc, and Duke and AEP also filed for rehearing, which was denied by the Sixth Circuit on March 26, 2025. On April 16, 2025, the Sixth Circuit agreed to hold the case pending further appeal to the Supreme Court of the U.S. The deadline to file for review at the Supreme Court of the U.S. is June 25, 2025.
Transmission ROE Methodology
A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 and remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis; provided however, due to the Sixth Circuit’s ruling in the Transmission ROE Incentive matter described above, ATSI is collecting the ROE incentive adder subject to refund.
Transmission Planning Supplement Projects
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. Subsequently, intervenors expanded the scope of this proceeding to all of the transmission utilities in PJM, including JCP&L. ATSI and the other transmission utilities in Ohio and PJM filed comments.
Local Transmission Planning Complaint
On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates. The complaint demands that FERC: (i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100kV or higher, (ii) appoint “independent transmission monitors” to conduct such planning, and (iii) condition construction of local transmission facilities on the facility having been planned by the “independent transmission monitor.” FirstEnergy is participating in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. FirstEnergy, together with the PJM transmission owners, filed a motion to dismiss the complaint on March 20, 2025, which is pending before FERC. FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy and its transmission capital investment strategy.
Ghiorzi v. PJM
In December 2023, PJM assigned certain baseline RTEP projects to NextEra Energy Transmission, which subsequently informed PJM that it would not construct the projects. On April 3, 2025, following the reassignment by PJM of certain baseline RTEP projects in Maryland and Virginia to PE, two individuals filed a complaint at FERC challenging this outcome. The complainants assert that PJM erred in reassigning the work to PE because such reassignment projects: (i) did not reflect the cost estimates or cost caps included in NextEra Energy Transmission’s bid and (ii) would be constructed with different routing than as originally proposed. FERC set May 7, 2025, as the deadline for intervention and comment. PE has intervened and plans to submit comments on May 7, 2025. FirstEnergy and PE are unable to predict the outcome or estimate the impact that this complaint may have.
Valley Link Formula Transmission Rate
Valley Link is a joint venture between FET, AEP and Dominion, and was formed to submit applications to construct transmission solutions to identified transmission reliability issues. In 2024, Valley Link submitted a portfolio of transmission solutions to the reliability issues that were the subject of the PJM 2024 RTEP Window 1 planning process. On February 26, 2025, PJM selected approximately $3.0 billion of the transmission solutions proposed by Valley Link for construction through PJM’s “baseline” RTEP process. On March 14, 2025, the Valley Link joint venture filed an application for forward-looking formula transmission rates to provide for cost recovery for the portfolio of selected projects. Among other things, the transmission rate application provides for a capital structure of 40% debt and 60% equity, and a base ROE of 10.9% with associated templates and protocols, as well as transmission rate incentives, including the abandonment rate incentive, the construction work in progress rate incentive, the RTO participation adder incentive, the hypothetical capital structure incentive, and the regulatory asset incentive. On April 4, 2025, certain parties filed protests of certain elements of the proposed formula rate and requested transmission incentives, to which Valley Link responded on April 21, 2025.
On April 8, 2025, PJM also sought to intervene in the matter. FERC is expected to issue an initial order by May 13, 2025.
10. COMMITMENTS, GUARANTEES AND CONTINGENCIES
The disclosures in this note apply to both Registrants, unless indicated otherwise.
FIRSTENERGY - GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications, which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FE and its subsidiaries could be required to make under these guarantees as of March 31, 2025, was approximately $1.1 billion, as summarized below:
|
|
|
|
|
|
|
|
|
| Guarantees and Other Assurances |
|
Maximum Exposure |
| |
|
(In millions) |
| FE’s Guarantees on Behalf of its Consolidated Subsidiaries |
|
|
| Deferred compensation arrangements |
|
$ |
403 |
|
| Vehicle leases |
|
75 |
|
| McElroy Run transfer |
|
144 |
|
| Other |
|
29 |
|
|
|
651 |
|
| FE’s Guarantees on Other Assurances |
|
|
| Surety Bonds |
|
167 |
|
| Deferred compensation arrangements |
|
96 |
|
| LOCs |
|
177 |
|
|
|
440 |
|
| Total Guarantees and Other Assurances |
|
$ |
1,091 |
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JCP&L - GUARANTEES AND OTHER ASSURANCES
JCP&L has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include stand-by LOCs and surety bonds. JCP&L 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 JCP&L could be required to make under these guarantees as of March 31, 2025, was $48 million as summarized below:
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| Guarantees and Other Assurances |
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Maximum Exposure |
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(In millions) |
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| Surety Bonds |
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$ |
20 |
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| LOCs |
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28 |
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| Total Guarantees and Other Assurances |
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$ |
48 |
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FIRSTENERGY - 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 March 31, 2025, $177 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $66 million of net cash collateral as of March 31, 2025, from certain generation suppliers, and such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of March 31, 2025:
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| Potential Collateral Obligations |
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Electric Companies and Transmission Companies |
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FE |
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Total |
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(In millions) |
| Contractual obligations for additional collateral |
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| Upon downgrade |
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$ |
71 |
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$ |
1 |
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$ |
72 |
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Surety bonds (collateralized amount)(1) |
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102 |
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193 |
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295 |
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| Total Exposure from Contractual Obligations |
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$ |
173 |
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$ |
194 |
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$ |
367 |
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(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 $38 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
JCP&L - COLLATERAL AND CONTINGENT-RELATED FEATURES
In the normal course of business, JCP&L 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 JCP&L to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon JCP&L's credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
JCP&L has posted $28 million of collateral in the form of LOCs as of March 31, 2025. JCP&L is holding $21 million of net cash collateral as of March 31, 2025, from certain generation suppliers, and such amount is included in "Other current liabilities" on JCP&L's Balance Sheets.
These credit-risk-related contingent features stipulate that if JCP&L were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of March 31, 2025:
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| Potential Collateral Obligations |
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JCP&L |
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(In millions) |
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| Contractual obligations for additional collateral |
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| Upon downgrade |
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$ |
38 |
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Surety bonds (collateralized amount)(1) |
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20 |
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| Total Exposure from Contractual Obligations |
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$ |
58 |
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(1) Surety bonds are not tied to a credit rating, and their impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $1 million as of March 31, 2025 of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate the Registrants with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While the Registrants’ 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. The Registrants 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 their business, results of operations, cash flows and financial condition. In general, environmental requirements applicable to the electric power sector are becoming increasingly prescriptive and stringent, and the EPA finalized a number of rules in 2024 that could impact the Registrants. However, the Trump administration has issued certain executive orders and stated its intention to rescind, revise or replace some existing environmental regulations and the ultimate impact of recently finalized rules, several of which are in litigation, and any replacement rules are uncertain.
On March 12, 2025, the EPA announced its intent to reevaluate or reconsider numerous environmental regulations, many of which apply to the Registrants. The specific timing or outcome of this initiative remains unknown, but regular required rulemaking processes and procedures still apply, and litigation is also anticipated to occur. The following disclosures do not attempt to discern potential impacts of these deregulatory actions until and unless formal rulemaking or other regulatory actions are announced and the potential impacts to operations can be discerned.
The disclosures below apply to FirstEnergy and the disclosures under “Regulation of Waste Disposal,” are also applicable to JCP&L.
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 Supreme Court of the U.S. ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.
Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the Supreme Court of the U.S. Oral argument was heard on February 21, 2024. On June 27, 2024, the Supreme Court of the U.S. granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. On February 6, 2025, the EPA filed a motion at the D.C. Circuit to hold the proceedings in abeyance for 60 days to allow the EPA time to familiarize itself with the Good Neighbor Plan and in particular, time to brief the new administration about these consolidated petitions and the underlying Rule to allow them to decide what action, if any, is necessary. On February 21, 2025, the D.C. Circuit denied the EPA’s motion and scheduled oral argument on the merits for April 25, 2025. On March 10, 2025, the EPA filed a motion for remand with the D.C. Circuit identifying issues with the Good Neighbor Plan that make reconsideration appropriate. The D.C. Circuit granted the motion for remand and cancelled oral argument. Consistent with its March 12, 2025, announcement, the EPA intends to undertake reconsideration of the rule and complete any new rulemaking by Fall 2026.
Climate Change
In recent years, certain regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. At the federal level, presidential administrations have held differing views on prioritizing actions to address GHG emissions and, by extension, climate change. Those differing views have led to policy changes, creating uncertainty about environmental requirements and associated impacts.
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 Supreme Court of the U.S. stayed the rule during the pendency of the challenges to the D.C.
Circuit and Supreme Court of the U.S. 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 Supreme Court of the U.S. in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule in the D.C. Circuit. On July 19, 2024, the D.C. Circuit denied the stay motions and on July 23 and 26, 2024 the aggrieved petitioners filed emergency stay applications to the Supreme Court of the U.S. On October 16, 2024, the Supreme Court of the U.S. denied the stay applications. On December 6, 2024, oral arguments on the merits of the challenge were heard by the D.C. Circuit. On February 5, 2025, the Department of Justice filed an unopposed motion on behalf of EPA in the D.C. Circuit, seeking to hold the litigation in abeyance, and forego issuing its opinion, for a period of 60 days while the new leadership at EPA evaluates the rule and determines how it wishes to proceed On February 19, 2025, the D.C. Circuit granted EPA’s motion.
Most recently, among other deregulatory actions, Executive Order 14514 directs the Administrator of the EPA to make recommendations on the “legality and continuing applicability” of the 2009 Endangerment Finding, which forms the basis for the EPA's GHG regulations. On March 12, 2025, the EPA announced a series of planned deregulatory actions that it would be taking related to such executive order, including reconsideration of the regulations to limit power plant GHG emissions. Depending on the outcome of any appeals and the EPA review, compliance with the GHG emissions limits could require additional capital expenditures or changes in operation at the Fort Martin and Harrison power stations.
In addition, there are several initiatives to reduce GHG emissions at the state and international level. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.
FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). FirstEnergy’s ability to achieve its GHG reduction goal is subject to its ability to make operational changes and is conditioned upon numerous risks, many of which are outside of its control. With respect to FirstEnergy’s coal-fired plants in West Virginia, which serve as the primary source of its Scope 1 emissions, it has 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 FirstEnergy is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s financial condition, results of operations, and cash flow. 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.
FirstEnergy continues to monitor climate change policies at both the federal and state level. Currently, FirstEnergy anticipates continued uncertainty, and may need to make decisions even as policies shift from administration to administration.
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 were renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025, for both.
In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the U.S. Court of Appeals for the Fifth and Eighth Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the rule pending disposition on the merits. A number of other parties have challenged the final rule in various petitions for review across several circuits. Those petitions and motions for stay have been consolidated in the U.S. Court of Appeals for the Eighth Circuit Court. On October 10, 2024, the Eighth Circuit denied the motions for stay. On February 19, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. On February 28, 2025, the D.C. Circuit granted EPA’s motion. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the 2024 ELG rule. Depending on the outcome of appeals and the EPA’s review, compliance with the 2024 ELG rule could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. During 2024, as a result of the evaluation of closure options for McElroy’s Run and the adjacent landfill, AE Supply reviewed its ARO and future expected costs to remediate, resulting in an increase to the ARO liability of $87 million. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025 with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. In connection with the transfer, AE Supply made a $15 million cash payment to the escrow account, recognized a $130 million liability, based on a 4.8% weighted average discount rate over the contract term, associated with its remaining obligation to fund the escrow account over the next five years, and derecognized the ARO, resulting in an immaterial impact to earnings.
On May 8, 2024, the EPA issued the Legacy CCR Rule, which finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. On February 13, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation, which was filed on August 8, 2024, by the Utility Solid Waste Act Group with FE as a member, in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed, which the D.C. Circuit granted. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the final Legacy CCR Rule. FirstEnergy continues to monitor the EPA’s actions related to CCR regulations; however, the ultimate impact is unknown at this time and is subject to the outcome of the litigation and any future state regulatory actions. Depending on the outcome of appeals and the EPA’s rule, compliance with the final Legacy CCR Rule could require remedial actions, including removal of coal ash. See Note 8, “Asset Retirement Obligations,” of the Combined Notes to Financial Statements of the Registrants above for a description of the $139 million increase to its ARO that FirstEnergy recorded during 2024 as a result of its analysis. JCP&L did not have any legacy CCR disposal sites that were applicable to the new CCR rule.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of March 31, 2025, 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 $98 million have been accrued through March 31, 2025, of which approximately $69 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
U.S. v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the U.S. Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District of Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. On January 17, 2025, the U.S. Attorney’s Office announced that a federal grand jury charged two former FirstEnergy senior officers with one count of participating in a Racketeer Influenced and Corrupt Organizations Act conspiracy. The allegations in the indictment are largely based on the conduct described in the DPA.
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 as to FE. Under the DPA, FE agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA required 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, consisting of (x) $115 million paid by FE to the U.S. Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 22, 2024, FirstEnergy had successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S. Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the aforementioned federal indictment against two former FirstEnergy senior officers. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information. On February 26, 2025, the U.S. Attorney’s Office filed a status report confirming these commitments.
Legal Proceedings Relating to U.S. v. Larry Householder, et al.
Certain FE stockholders and FirstEnergy customers also 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 alleged 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 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order; the Sixth Circuit granted FE’s petition on November 16, 2023, and heard oral argument on July 17, 2024. On November 30, 2023, FE filed a motion with the S.D. Ohio to stay all proceedings pending that circuit court appeal. Discovery was stayed during the pendency of that motion to stay all proceedings and on August 20, 2024, the S.D. Ohio denied FE’s motion and lifted the stay as to fact discovery. On July 29, 2024, FE filed in the U.S. Court of Appeals for the Sixth Circuit a Petition for Writ of Mandamus asking the Sixth Circuit to direct the district court to deny plaintiffs’ motion to compel disclosure of FE’s privileged internal investigation materials. On September 11, 2024, FE filed in the U.S. Court of Appeals for the Sixth Circuit a motion to stay discovery of the privileged internal investigation materials pending resolution of the Petition for Writ of Mandamus. 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 then-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. 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.
The outcome of any of these lawsuits 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 the Registrants’ normal business operations pending against them or their subsidiaries. The loss or range of loss in these matters is not expected to be material to the Registrants. The other potentially material items not otherwise discussed above are described under Note 9, “Regulatory Matters” of the Combined Notes to Financial Statements of the Registrants.
The Registrants accrue 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 the Registrants determine that it is not probable, but reasonably possible that they have a material obligation, they disclose such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that the Registrants 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 the Registrants’ financial condition, results of operations, and cash flows.
11. SEGMENT INFORMATION
The disclosures in this note apply to both Registrants, unless indicated otherwise.
FirstEnergy
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission. FirstEnergy’s CODM evaluates segment performance based on earnings attributable to FE. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer, its CODM, to regularly assess performance of the business, make operating decisions and allocate resources.
The Distribution segment, which consists of the Ohio Companies and FE PA, distributes electricity through FirstEnergy’s electric operating companies in Ohio and Pennsylvania. The Distribution segment serves approximately 4.3 million customers in Ohio and Pennsylvania across its distribution footprint and purchases power for its provider of last resort, SOS, standard service offer and default service requirements. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.
The Integrated segment includes the distribution and transmission operations under JCP&L, MP and PE, as well as MP’s regulated generation operations. The Integrated segment distributes electricity to approximately 2 million customers in New Jersey, West Virginia and Maryland across its distribution footprint; provides transmission infrastructure in New Jersey, West Virginia, Maryland and Virginia to transmit electricity and operates 3,604 MWs of regulated net maximum generation capacity located primarily in West Virginia and Virginia. The segment will also include MP and PE’s 50 MWs of solar generation at five sites in West Virginia once complete. The first two solar generation sites were completed and placed in service in 2024, representing 24 MWs of net maximum generation capacity. The remaining three sites are expected to provide 26 MWs of net maximum generation capacity.
The Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, includes transmission infrastructure owned and operated by the Transmission Companies and used to transmit electricity.
The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.
Corporate/Other reflects corporate support and other costs not charged or attributable to the Electric Companies or Transmission Companies, including FE’s retained pension and OPEB assets and liabilities of former subsidiaries, interest expense on FE’s holding company debt and other investments or businesses that do not constitute an operating segment, including FEV’s investment of 33-1/3% equity ownership in Global Holding. Reconciling adjustments for the elimination of inter-segment transactions are shown separately in the following table of Segment Financial Information. Also included in Corporate/Other for segment reporting is 67 MWs of net maximum generation capacity, representing AE Supply’s OVEC capacity entitlement. As of March 31, 2025, Corporate/Other had approximately $6.5 billion of external FE holding company debt.
Financial information for FirstEnergy’s reportable segments and reconciliations to consolidated amounts is presented below:
|
|
|
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|
|
|
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|
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|
|
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|
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
Distribution |
|
Integrated |
|
Stand-Alone Transmission |
|
Total Reportable
Segments |
|
Corporate/ Other |
|
Reconciling Adjustments |
|
FirstEnergy Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
| March 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| External revenues |
|
$ |
1,927 |
|
|
$ |
1,348 |
|
|
$ |
486 |
|
|
$ |
3,761 |
|
|
$ |
4 |
|
|
$ |
— |
|
|
$ |
3,765 |
|
| Internal revenues |
|
9 |
|
|
1 |
|
|
5 |
|
|
15 |
|
|
— |
|
|
(15) |
|
|
— |
|
| Total revenues |
|
$ |
1,936 |
|
|
$ |
1,349 |
|
|
$ |
491 |
|
|
$ |
3,776 |
|
|
$ |
4 |
|
|
$ |
(15) |
|
|
$ |
3,765 |
|
Other operating expenses(1) |
|
627 |
|
|
337 |
|
|
98 |
|
|
1,062 |
|
|
(25) |
|
|
(3) |
|
|
1,034 |
|
Depreciation(1) |
|
162 |
|
|
138 |
|
|
91 |
|
|
391 |
|
|
20 |
|
|
— |
|
|
411 |
|
| Amortization (deferral) of regulatory assets, net |
|
(19) |
|
|
8 |
|
|
1 |
|
|
(10) |
|
|
— |
|
|
— |
|
|
(10) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense(1) |
|
99 |
|
|
65 |
|
|
73 |
|
|
237 |
|
|
79 |
|
|
(28) |
|
|
288 |
|
Income taxes (benefits)(1) |
|
60 |
|
|
40 |
|
|
40 |
|
|
140 |
|
|
(14) |
|
|
— |
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense (income) items(2) |
|
789 |
|
|
625 |
|
|
107 |
|
|
1,521 |
|
|
7 |
|
|
28 |
|
|
1,556 |
|
| Earnings attributable to FE |
|
218 |
|
|
136 |
|
|
81 |
|
|
435 |
|
|
(75) |
|
|
— |
|
|
360 |
|
| Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capital investments |
|
$ |
265 |
|
|
$ |
395 |
|
|
$ |
314 |
|
|
$ |
974 |
|
|
$ |
31 |
|
|
$ |
— |
|
|
$ |
1,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| March 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| External revenues |
|
$ |
1,756 |
|
|
$ |
1,094 |
|
|
$ |
434 |
|
|
$ |
3,284 |
|
|
$ |
3 |
|
|
$ |
— |
|
|
$ |
3,287 |
|
| Internal revenues |
|
11 |
|
|
1 |
|
|
4 |
|
|
16 |
|
|
— |
|
|
(16) |
|
|
— |
|
| Total revenues |
|
$ |
1,767 |
|
|
$ |
1,095 |
|
|
$ |
438 |
|
|
$ |
3,300 |
|
|
$ |
3 |
|
|
$ |
(16) |
|
|
$ |
3,287 |
|
Other operating expenses(1) |
|
587 |
|
|
354 |
|
|
76 |
|
|
1,017 |
|
|
(8) |
|
|
(3) |
|
|
1,006 |
|
Depreciation(1) |
|
161 |
|
|
122 |
|
|
81 |
|
|
364 |
|
|
17 |
|
|
— |
|
|
381 |
|
| Amortization (deferral) of regulatory assets, net |
|
(88) |
|
|
(78) |
|
|
2 |
|
|
(164) |
|
|
— |
|
|
— |
|
|
(164) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Equity method investment earnings, net |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
21 |
|
|
— |
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense(1) |
|
116 |
|
|
71 |
|
|
65 |
|
|
252 |
|
|
117 |
|
|
(64) |
|
|
305 |
|
Income taxes (benefits)(1) |
|
41 |
|
|
35 |
|
|
60 |
|
|
136 |
|
|
(1) |
|
|
— |
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense (income) items(2) |
|
785 |
|
|
509 |
|
|
70 |
|
|
1,364 |
|
|
(36) |
|
|
64 |
|
|
1,392 |
|
| Earnings attributable to FE |
|
165 |
|
|
82 |
|
|
84 |
|
|
331 |
|
|
(78) |
|
|
— |
|
|
253 |
|
| Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capital investments |
|
$ |
215 |
|
|
$ |
313 |
|
|
$ |
258 |
|
|
$ |
786 |
|
|
$ |
4 |
|
|
$ |
— |
|
|
$ |
790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
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|
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|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As of March 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets |
|
$ |
20,372 |
|
|
$ |
18,812 |
|
|
$ |
13,665 |
|
|
$ |
52,849 |
|
|
$ |
1,837 |
|
|
$ |
(1,915) |
|
|
$ |
52,771 |
|
| Total goodwill |
|
$ |
3,222 |
|
|
$ |
1,953 |
|
|
$ |
443 |
|
|
$ |
5,618 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
5,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets |
|
$ |
19,949 |
|
|
$ |
18,637 |
|
|
$ |
13,528 |
|
|
$ |
52,114 |
|
|
$ |
1,975 |
|
|
$ |
(2,045) |
|
|
$ |
52,044 |
|
| Total goodwill |
|
$ |
3,222 |
|
|
$ |
1,953 |
|
|
$ |
443 |
|
|
$ |
5,618 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
5,618 |
|
(1) FirstEnergy considers this line to be a significant expense.
(2) Consists of Fuel, Purchased power, General taxes, Miscellaneous income, net, Capitalized financing costs, and Income attributable to noncontrolling interest.
JCP&L
JCP&L is principally involved in the transmission and distribution of electricity through its reportable segments: Distribution and Transmission. JCP&L's CODM evaluates performance based on net income. The external segment reporting is consistent with the internal financial reports used by JCP&L's President, its CODM, to regularly assess performance of the business, make operating decisions and allocate resources.
JCP&L’s Distribution segment distributes electricity to approximately 1.2 million customers in New Jersey across its distribution footprint and procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.
JCP&L’s Transmission segment includes transmission infrastructure owned and operated by JCP&L and used to transmit electricity. The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on JCP&L’s transmission facilities.
Financial information for JCP&L’s reportable segments and reconciliations are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
Distribution |
|
Transmission |
|
Total Reportable
Segments |
|
|
|
Reconciling Adjustments |
|
JCP&L |
|
|
(In millions) |
| March 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
| External revenues |
|
$ |
505 |
|
|
$ |
61 |
|
|
$ |
566 |
|
|
|
|
$ |
— |
|
|
$ |
566 |
|
| Internal revenues |
|
43 |
|
|
— |
|
|
43 |
|
|
|
|
(43) |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total revenues |
|
$ |
548 |
|
|
$ |
61 |
|
|
$ |
609 |
|
|
|
|
$ |
(43) |
|
|
$ |
566 |
|
Other operating expenses(1) |
|
174 |
|
|
14 |
|
|
188 |
|
|
|
|
(43) |
|
|
145 |
|
Depreciation(1) |
|
53 |
|
|
12 |
|
|
65 |
|
|
|
|
— |
|
|
65 |
|
| Deferral of regulatory assets, net |
|
(22) |
|
|
— |
|
|
(22) |
|
|
|
|
— |
|
|
(22) |
|
Interest expense - other(1) |
|
22 |
|
|
7 |
|
|
29 |
|
|
|
|
— |
|
|
29 |
|
Interest expense - affiliates(1) |
|
1 |
|
|
— |
|
|
1 |
|
|
|
|
— |
|
|
1 |
|
| Income taxes |
|
7 |
|
|
9 |
|
|
16 |
|
|
|
|
— |
|
|
16 |
|
Other expense (income) items(2) |
|
289 |
|
|
(6) |
|
|
283 |
|
|
|
|
— |
|
|
283 |
|
| Net Income |
|
24 |
|
|
25 |
|
|
49 |
|
|
|
|
— |
|
|
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Capital investments |
|
$ |
74 |
|
|
$ |
132 |
|
|
$ |
206 |
|
|
|
|
$ |
— |
|
|
$ |
206 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| March 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
| External revenues |
|
$ |
414 |
|
|
$ |
52 |
|
|
$ |
466 |
|
|
|
|
$ |
— |
|
|
$ |
466 |
|
| Internal revenues |
|
38 |
|
|
— |
|
|
38 |
|
|
|
|
(38) |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total revenues |
|
$ |
452 |
|
|
$ |
52 |
|
|
$ |
504 |
|
|
|
|
$ |
(38) |
|
|
$ |
466 |
|
Other operating expenses(1) |
|
211 |
|
|
14 |
|
|
225 |
|
|
|
|
(38) |
|
|
187 |
|
Depreciation(1) |
|
50 |
|
|
11 |
|
|
61 |
|
|
|
|
— |
|
|
61 |
|
| Deferral of regulatory assets, net |
|
(39) |
|
|
— |
|
|
(39) |
|
|
|
|
— |
|
|
(39) |
|
Interest expense - other(1) |
|
23 |
|
|
7 |
|
|
30 |
|
|
|
|
— |
|
|
30 |
|
Interest expense - affiliates(1) |
|
4 |
|
|
— |
|
|
4 |
|
|
|
|
— |
|
|
4 |
|
| Income taxes (benefits) |
|
(11) |
|
|
7 |
|
|
(4) |
|
|
|
|
— |
|
|
(4) |
|
Other expense (income) items(2) |
|
240 |
|
|
(5) |
|
|
235 |
|
|
|
|
— |
|
|
235 |
|
| Net Income (Loss) |
|
(26) |
|
|
18 |
|
|
(8) |
|
|
|
|
— |
|
|
(8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Capital investments |
|
$ |
71 |
|
|
$ |
123 |
|
|
$ |
194 |
|
|
|
|
$ |
— |
|
|
$ |
194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As of March 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets |
|
$ |
7,271 |
|
|
$ |
2,802 |
|
|
$ |
10,073 |
|
|
|
|
$ |
— |
|
|
$ |
10,073 |
|
| Total goodwill |
|
$ |
1,213 |
|
|
$ |
598 |
|
|
$ |
1,811 |
|
|
|
|
$ |
— |
|
|
$ |
1,811 |
|
| As of December 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets |
|
$ |
7,212 |
|
|
$ |
2,715 |
|
|
$ |
9,927 |
|
|
|
|
$ |
— |
|
|
$ |
9,927 |
|
| Total goodwill |
|
$ |
1,213 |
|
|
$ |
598 |
|
|
$ |
1,811 |
|
|
|
|
$ |
— |
|
|
$ |
1,811 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) JCP&L considers this line to be a significant expense.
(2) Consists of Purchased power, General taxes, Miscellaneous income, net, Interest income from affiliates, and Capitalized financing costs.
12. TRANSACTIONS WITH AFFILIATES
The disclosures in this note apply to JCP&L only.
The affiliated company transactions for JCP&L for the three months ended March 31, 2025 and 2024 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31 |
|
|
2025 |
|
2024 |
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
| Revenues |
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
| Expenses: |
|
|
|
|
|
|
|
|
|
FESC support services (1) |
|
50 |
|
|
43 |
|
Other affiliate support services (1) |
|
4 |
|
|
4 |
|
| Interest income |
|
— |
|
|
— |
|
| Interest expense |
|
1 |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes amounts capitalized.
FE does not bill directly or allocate any of its costs to any subsidiary 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. 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. JCP&L can also receive charges from and charge affiliates other than FESC at cost.
JCP&L recognizes an allocation of the net periodic pension and OPEB costs/credits from its affiliates, primarily FESC.
Under the FirstEnergy regulated money pool, JCP&L has the ability to borrow from its regulated affiliates and FE to meet its short-term working capital requirements. Affiliated company notes receivables and payables related to the money pool are reported as Notes receivable from affiliated companies or Short-term borrowings - affiliated companies on the Balance Sheets. Affiliate accounts receivable and accounts payable balances relate to intercompany transactions that have not yet settled through the FirstEnergy money pool.
JCP&L is party to an intercompany income tax allocation agreement with FirstEnergy that provides for the allocation of consolidated tax liabilities.
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY AND RECENT DEVELOPMENTS
Company Overview
FirstEnergy is dedicated to integrity, safety, reliability and operational excellence and is principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission. Its electric distribution companies form one of the nation's largest investor-owned electric systems, serving over six million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. FirstEnergy’s transmission subsidiaries operate more than 24,000 miles of transmission lines that connect the Midwest and Mid-Atlantic regions and two regional transmission operation centers. As of March 31, 2025, AGC and MP control 3,604 MWs of net maximum generation capacity.
FIRSTENERGY’S CONSOLIDATED RESULTS OF OPERATIONS
First Quarter of 2025 Compared with First Quarter of 2024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions) |
|
For the Three Months Ended March 31, |
|
|
|
|
2025 |
|
2024 |
|
Increase (Decrease) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenues |
|
$ |
3,765 |
|
|
$ |
3,287 |
|
|
$ |
478 |
|
|
15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating expenses |
|
(3,011) |
|
|
(2,675) |
|
|
336 |
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other expenses, net |
|
(214) |
|
|
(210) |
|
|
4 |
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income taxes |
|
(126) |
|
|
(135) |
|
|
(9) |
|
|
(7) |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income attributable to noncontrolling interest |
|
(54) |
|
|
(14) |
|
|
40 |
|
|
286 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Earnings attributable to FE |
|
$ |
360 |
|
|
$ |
253 |
|
|
$ |
107 |
|
|
42 |
% |
|
|
|
|
|
|
|
|
Earnings attributable to FE was $360 million or $0.62 per share (basic and diluted) in the first quarter of 2025 compared to $253 million or $0.44 per share (basic and diluted) in the first quarter of 2024, representing an increase of $107 million that was primarily due to the following:
•Higher revenues associated with the implementation of base rate cases in New Jersey, West Virginia and Pennsylvania;
•Higher customer usage as a result of the colder weather temperatures;
•Higher revenues from regulated capital investments that increased rate base;
•The absence of a $53 million charge at JCP&L in connection with the base rate case settlement agreement in the first quarter of 2024, as further discussed below;
•Lower interest expense as a result of long-term debt redemptions since the first quarter of 2024 and lower short-term borrowings; and
•The absence of discrete tax charges related to the FET Equity Interest Sale and PA Consolidation in the first quarter of 2024.
These factors were partially offset by the following:
•Lower weather-adjusted customer usage and demand;
•The absence of a benefit associated with the approval by the WVPSC to recover costs of certain retired generation stations in the first quarter of 2024;
•The expected elimination of ATSI’s 50 basis point adder associated with RTO membership as a result of the Sixth Circuit ruling in January 2025;
•Higher depreciation expense due to a higher asset base;
•Lower investment earnings related to FEV’s equity method investment in Global Holding;
•Costs associated with the announced organizational changes; and
•The dilutive effect of the FET Equity Interest Sale that closed in March 2024.
Detailed segment reporting explanations are included below.
Distribution services by customer class are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
|
|
|
|
|
| (In thousands) |
|
Actual |
|
Weather-Adjusted |
|
| Electric Distribution MWh Deliveries |
|
2025 |
|
2024 |
|
Increase (Decrease) |
|
2025 |
|
2024 |
|
(Decrease) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
15,491 |
|
|
14,087 |
|
|
10.0 |
% |
|
15,384 |
|
|
15,493 |
|
|
(0.7) |
% |
|
|
|
|
|
Commercial(1) |
|
9,844 |
|
|
9,357 |
|
|
5.2 |
% |
|
9,858 |
|
|
9,896 |
|
|
(0.4) |
% |
|
|
|
|
|
| Industrial |
|
12,837 |
|
|
13,182 |
|
|
(2.6) |
% |
|
12,837 |
|
|
13,182 |
|
|
(2.6) |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Electric Distribution MWh Deliveries |
|
38,172 |
|
|
36,626 |
|
|
4.2 |
% |
|
38,079 |
|
|
38,571 |
|
|
(1.3) |
% |
|
|
|
|
|
(1) Includes street lighting.
Residential and commercial distribution deliveries were impacted by higher customer usage as a result of the weather. Heating degree days in the first quarter of 2025 were 15% above the same period of 2024 and flat to normal.
Recent Developments
Asset Retirement Obligations
On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments, and in November 2024 and January 2025, the EPA made several technical corrections to the rule. The rule extends 2015 CCR rule requirements for groundwater monitoring and protection procedures, operational and reporting procedures, as well as closure requirements for impoundments and landfills that were not originally included for coverage by the 2015 CCR rule. As a result, during 2024, FirstEnergy performed a preliminary assessment of former CCR disposal sites and calculated an initial estimate applying historical experience in remediating comparable sites and recorded a $139 million increase to its ARO in 2024. JCP&L did not have any legacy CCR disposal sites that were applicable to the new CCR rule.
During 2024, as a result of the evaluation of closure options for McElroy’s Run and the adjacent landfill, AE Supply reviewed its ARO and future expected costs to remediate, resulting in an increase to the ARO liability of $87 million. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025, with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. In connection with the transfer, AE Supply made a $15 million cash payment to the escrow account, recognized a $130 million liability, based on a 4.8% weighted average discount rate over the contract term, associated with its remaining obligation to fund the escrow account over the next five years, and derecognized the ARO, resulting in an immaterial impact to earnings.
On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the final legacy CCR rules. We continue to monitor EPA's actions related to CCR; however, the ultimate impact is unknown at this time and subject to the outcome of the litigation and any future state regulatory actions.
Valley Link
On July 26, 2024, FE, VEPCO and Transource Energy, LLC, a subsidiary of AEP, entered into a joint proposal agreement in connection with PJM’s 2024 Regional Transmission Expansion Plan Open Window 1 process. Pursuant to such joint proposal agreement, FET, VEPCO and Transource Energy, LLC jointly proposed certain regional electric transmission projects for PJM's consideration during the Open Window process. On November 25, 2024, FET, Dominion High Voltage MidAtlantic, Inc., an affiliate of VEPCO, and Transource Energy, LLC, formed Valley Link, which is the holding company responsible for managing and executing any projects awarded by PJM, and entered into a limited liability agreement. On February 26, 2025, PJM selected certain of the joint proposed projects, which included approximately $3 billion in investments for Valley Link to both build new and upgrade existing transmission infrastructure.
Reorganization
On March 24, 2025, FirstEnergy internally announced organizational changes to FirstEnergy employees. These organizational changes are intended to align FirstEnergy’s organization with its new business model, which is designed to make FE more efficient and sustainable while placing responsibility and accountability closer to customers, employees and regulators. The changes are also consistent with FirstEnergy’s focus on operations and maintenance expense discipline. These organizational changes resulted in approximately two hundred employees being reassigned and FirstEnergy reducing its workforce by less than three percent. As a result, FirstEnergy recognized a pre-tax charge of approximately $26 million ($5 million at JCP&L) during the first quarter of 2025, which is included within “Other operating expenses” on each of the Registrant’s Statements of Income and Comprehensive Income.
Dividend Growth
FirstEnergy continues to return value to shareholders. In March 2025, the FE Board declared a $0.02 per share increase to the quarterly common stock dividend payable June 1, 2025, to $0.445 per share, which represents an increase of more than 11% in annual dividend declarations since 2023. Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings growth, credit metrics and other business conditions.
Regulatory Matters - New Jersey
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. On April 10, 2025, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s amended EnergizeNJ petition. The settlement provides for total program costs of $339 million, including capital investments in JCP&L’s electric distribution system of approximately $203 million, $132 million of matching capital investments and approximately $4 million of O&M expense. Pursuant to the settlement, the program would begin on July 1, 2025, and continue through December 31, 2028, and JCP&L has agreed to file a base rate case no later than January 1, 2030.
Regulatory Matters - Ohio
On April 5, 2023, the Ohio Companies sought approval from the PUCO for their ESP V. The proposed plan would maintain an eight-year term beginning June 1, 2024, and continue riders recovering costs associated with distribution infrastructure investments and approved grid modernization investments. ESP V additionally proposed new riders that would support reliability, and included provisions supporting affordability and enhancing the customer experience. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which are described below in “Outlook - State Regulation - Ohio”. On June 14, 2024, the Ohio Companies filed an Application for Rehearing, which was denied by operation of law as the PUCO did not rule on the applications for rehearing within 30 days of filing. Due to the risks and uncertainty resulting from the Ohio Companies’ application for rehearing being denied by operation of law, on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV, which was approved by the PUCO on December 18, 2024. On January 22, 2025, the PUCO approved the Ohio Companies’ ESP IV compliance tariffs with an effective date of February 1, 2025, at which point the Ohio Companies resumed operating under ESP IV with modifications, as described below in “Outlook - State Regulation - Ohio”. On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV.
On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI, which would begin concurrently with the effective date of any new base distribution rates resulting from the Ohio Companies’ pending base rate case and continue through May 31, 2028. ESP VI proposes to continue existing riders to support continued maintenance of the distribution system, and to reestablish riders to recover vegetation management and storm restoration expenses. ESP VI also includes provisions supporting affordability and enhancing the customer experience. The PUCO held a technical conference on March 12, 2025. Pending legislation in Ohio would, if enacted, eliminate the PUCO’s ability to authorize future ESPs; therefore, ESP VI could not move forward. Under such legislation, the Ohio Companies would be allowed to continue ESP IV until their final auction delivery period, which is May 31, 2029, and then ESP IV must terminate.
On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates, based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. The net increase represented a 1.5% average residential monthly bill increase. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual amount each year using this method. Additionally, the Ohio Companies requested recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony and on July 31, 2024, filed an update with an adjusted net increase of base distribution revenues of approximately $190 million and to incorporate matters in the rate case as directed by the PUCO’s ESP V order. On December 18, 2024, the PUCO issued an order approving the Ohio Companies’ withdrawal of ESP V. On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV. On January 27, 2025, the Ohio Companies notified the PUCO of their intention to update their application for an increase in base distribution rates to remove ESP V related provisions from the base rate case. The PUCO staff hired a third-party auditor to assist in the review of the Ohio Companies’ base rate case filing and on February 21, 2025, PUCO staff and the third party auditor each filed their reports. The auditor’s report recommended adjustments which would result in a net increase of the Ohio Companies’ base distribution revenues of approximately $8 million with a return on equity of 9.63% and capital structures of 48.8% debt and 51.2% equity for each of the Ohio Companies.
PUCO staff’s report takes limited positions on the auditor’s finding and recommendations and makes additional findings. On March 24, 2025, the Ohio Companies, OCC, and other parties filed objections to the PUCO’s staff report and the auditor’s report. In addition, the Ohio Companies filed certain pieces of supplemental testimony and intervenors filed direct testimony. The Ohio Companies and various parties are engaged in settlement discussions with respect to the pending base rate case. Evidentiary hearings are scheduled to begin on May 5, 2025.
HB 6 and Related Investigations
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the U.S. Attorney’s Office investigation into FirstEnergy relating to FirstEnergy’s lobbying and governmental affairs activities concerning HB 6 related to the federal criminal allegations made in July 2020, against former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Among other things under the DPA, FE paid a $230 million monetary penalty in 2021 and agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. As of July 22, 2024, FirstEnergy had successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S. Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the January 17, 2025, indictment against two former FirstEnergy senior officers, as described below in “Outlook -- Other Legal Proceedings - U.S. v. Larry Householder, et al.”. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information.
Despite these events, FirstEnergy has faced, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigations, the DPA, and ongoing litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the 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.
Summary of Results of Operations — First Quarter 2025 Compared with First Quarter 2024
Financial results for FirstEnergy’s business segments for the first quarter of 2025 and 2024 were as follows:
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|
First Quarter 2025 Financial Results
(In millions)
|
|
Distribution |
|
Integrated |
|
Stand-Alone Transmission |
|
Corporate/Other and Reconciling Adjustments |
|
FirstEnergy Consolidated |
| Revenues: |
|
|
|
|
|
|
|
|
|
|
| Electric |
|
$ |
1,896 |
|
|
$ |
1,333 |
|
|
$ |
486 |
|
|
$ |
4 |
|
|
$ |
3,719 |
|
| Other |
|
40 |
|
|
16 |
|
|
5 |
|
|
(15) |
|
|
46 |
|
| Total Revenues |
|
1,936 |
|
|
1,349 |
|
|
491 |
|
|
(11) |
|
|
3,765 |
|
|
|
|
|
|
|
|
|
|
|
|
| Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| Fuel |
|
— |
|
|
149 |
|
|
— |
|
|
— |
|
|
149 |
|
| Purchased power |
|
610 |
|
|
472 |
|
|
— |
|
|
6 |
|
|
1,088 |
|
| Other operating expenses |
|
627 |
|
|
337 |
|
|
98 |
|
|
(28) |
|
|
1,034 |
|
| Provision for depreciation |
|
162 |
|
|
138 |
|
|
91 |
|
|
20 |
|
|
411 |
|
| Amortization (deferral) of regulatory assets, net |
|
(19) |
|
|
8 |
|
|
1 |
|
|
— |
|
|
(10) |
|
| General taxes |
|
210 |
|
|
37 |
|
|
74 |
|
|
18 |
|
|
339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Expenses |
|
1,590 |
|
|
1,141 |
|
|
264 |
|
|
16 |
|
|
3,011 |
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
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| Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Equity method investment earnings, net |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
| Miscellaneous income (expense), net |
|
26 |
|
|
18 |
|
|
4 |
|
|
(12) |
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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| Interest expense |
|
(99) |
|
|
(65) |
|
|
(73) |
|
|
(51) |
|
|
(288) |
|
| Capitalized financing costs |
|
5 |
|
|
15 |
|
|
17 |
|
|
1 |
|
|
38 |
|
| Total Other Expense |
|
(68) |
|
|
(32) |
|
|
(52) |
|
|
(62) |
|
|
(214) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income taxes (benefits) |
|
60 |
|
|
40 |
|
|
40 |
|
|
(14) |
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income attributable to noncontrolling interest |
|
— |
|
|
— |
|
|
54 |
|
|
— |
|
|
54 |
|
|
|
|
|
|
|
|
|
|
|
|
| Earnings (Loss) Attributable to FE |
|
$ |
218 |
|
|
$ |
136 |
|
|
$ |
81 |
|
|
$ |
(75) |
|
|
$ |
360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter 2024 Financial Results
(In millions)
|
|
Distribution |
|
Integrated |
|
Stand-Alone Transmission |
|
Corporate/Other and Reconciling Adjustments |
|
FirstEnergy Consolidated |
| Revenues: |
|
|
|
|
|
|
|
|
|
|
| Electric |
|
$ |
1,725 |
|
|
$ |
1,082 |
|
|
$ |
434 |
|
|
$ |
3 |
|
|
$ |
3,244 |
|
| Other |
|
42 |
|
|
13 |
|
|
4 |
|
|
(16) |
|
|
43 |
|
| Total Revenues |
|
1,767 |
|
|
1,095 |
|
|
438 |
|
|
(13) |
|
|
3,287 |
|
|
|
|
|
|
|
|
|
|
|
|
| Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| Fuel |
|
— |
|
|
105 |
|
|
— |
|
|
— |
|
|
105 |
|
| Purchased power |
|
642 |
|
|
389 |
|
|
— |
|
|
5 |
|
|
1,036 |
|
| Other operating expenses |
|
587 |
|
|
354 |
|
|
76 |
|
|
(11) |
|
|
1,006 |
|
| Provision for depreciation |
|
161 |
|
|
122 |
|
|
81 |
|
|
17 |
|
|
381 |
|
| Amortization (deferral) of regulatory assets, net |
|
(88) |
|
|
(78) |
|
|
2 |
|
|
— |
|
|
(164) |
|
| General taxes |
|
192 |
|
|
38 |
|
|
69 |
|
|
12 |
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Expenses |
|
1,494 |
|
|
930 |
|
|
228 |
|
|
23 |
|
|
2,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Equity method investment earnings, net |
|
— |
|
|
— |
|
|
— |
|
|
21 |
|
|
21 |
|
| Miscellaneous income (expense), net |
|
44 |
|
|
12 |
|
|
— |
|
|
(12) |
|
|
44 |
|
|
|
|
|
|
|
|
|
|
|
|
| Interest expense |
|
(116) |
|
|
(71) |
|
|
(65) |
|
|
(53) |
|
|
(305) |
|
| Capitalized financing costs |
|
5 |
|
|
11 |
|
|
13 |
|
|
1 |
|
|
30 |
|
| Total Other Expense |
|
(67) |
|
|
(48) |
|
|
(52) |
|
|
(43) |
|
|
(210) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income taxes (benefits) |
|
41 |
|
|
35 |
|
|
60 |
|
|
(1) |
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income attributable to noncontrolling interest |
|
— |
|
|
— |
|
|
14 |
|
|
— |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
| Earnings (Loss) Attributable to FE |
|
$ |
165 |
|
|
$ |
82 |
|
|
$ |
84 |
|
|
$ |
(78) |
|
|
$ |
253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes Between First Quarter 2025 and First Quarter 2024 Financial Results
(In millions)
|
|
Distribution |
|
Integrated |
|
Transmission |
|
Corporate/Other and Reconciling Adjustments |
|
FirstEnergy Consolidated |
| Revenues: |
|
|
|
|
|
|
|
|
|
|
| Electric |
|
$ |
171 |
|
|
$ |
251 |
|
|
$ |
52 |
|
|
$ |
1 |
|
|
$ |
475 |
|
| Other |
|
(2) |
|
|
3 |
|
|
1 |
|
|
1 |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
| Total Revenues |
|
169 |
|
|
254 |
|
|
53 |
|
|
2 |
|
|
478 |
|
|
|
|
|
|
|
|
|
|
|
|
| Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| Fuel |
|
— |
|
|
44 |
|
|
— |
|
|
— |
|
|
44 |
|
| Purchased power |
|
(32) |
|
|
83 |
|
|
— |
|
|
1 |
|
|
52 |
|
| Other operating expenses |
|
40 |
|
|
(17) |
|
|
22 |
|
|
(17) |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
| Provision for depreciation |
|
1 |
|
|
16 |
|
|
10 |
|
|
3 |
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
| Amortization (deferral) of regulatory assets, net |
|
69 |
|
|
86 |
|
|
(1) |
|
|
— |
|
|
154 |
|
| General taxes |
|
18 |
|
|
(1) |
|
|
5 |
|
|
6 |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Expenses |
|
96 |
|
|
211 |
|
|
36 |
|
|
(7) |
|
|
336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Equity method investment earnings, net |
|
— |
|
|
— |
|
|
— |
|
|
(21) |
|
|
(21) |
|
| Miscellaneous income (expense), net |
|
(18) |
|
|
6 |
|
|
4 |
|
|
— |
|
|
(8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Interest expense |
|
17 |
|
|
6 |
|
|
(8) |
|
|
2 |
|
|
17 |
|
| Capitalized financing costs |
|
— |
|
|
4 |
|
|
4 |
|
|
— |
|
|
8 |
|
| Total Other Expense |
|
(1) |
|
|
16 |
|
|
— |
|
|
(19) |
|
|
(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income taxes (benefits) |
|
19 |
|
|
5 |
|
|
(20) |
|
|
(13) |
|
|
(9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income attributable to noncontrolling interest |
|
— |
|
|
— |
|
|
40 |
|
|
— |
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
| Earnings (Loss) Attributable to FE |
|
$ |
53 |
|
|
$ |
54 |
|
|
$ |
(3) |
|
|
$ |
3 |
|
|
$ |
107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution Segment — First Quarter of 2025 Compared with First Quarter of 2024
Distribution segment’s earnings attributable to FE increased $53 million in the first quarter of 2025, as compared to the same period of 2024, primarily resulting from higher customer usage as a result of the colder weather temperatures and higher revenues associated with the implementation of the Pennsylvania base rate case, partially offset by lower weather-adjusted customer usage and demand, and higher operating expenses.
Revenues —
Distribution’s total revenues increased $169 million as a result of the following sources:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| Revenues by Type of Service |
1 |
2025 |
|
2024 |
|
Increase (Decrease) |
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
| Distribution services |
|
$ |
1,179 |
|
2 |
|
$ |
1,020 |
|
|
$ |
159 |
|
|
|
|
|
|
|
| Generation sales: |
|
|
|
|
|
|
|
|
|
|
|
|
| Retail |
|
716 |
|
|
704 |
|
|
12 |
|
|
|
|
|
|
|
| Wholesale |
|
1 |
|
|
1 |
|
|
— |
|
|
|
|
|
|
|
| Total generation sales |
|
717 |
|
|
705 |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other |
|
40 |
|
|
42 |
|
|
(2) |
|
|
|
|
|
|
|
| Total Revenues |
|
$ |
1,936 |
|
|
$ |
1,767 |
|
|
$ |
169 |
|
|
|
|
|
|
|
Distribution services revenues increased $159 million in the first quarter of 2025, as compared to the same period of 2024, primarily resulting from higher customer usage as a result of the colder weather temperatures, lower customer credits associated with the PUCO-approved Ohio Stipulation, and higher revenues associated with the implementation of the Pennsylvania base rate case, partially offset by lower weather-adjusted customer usage and demand. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.
Generation sales revenues increased $12 million in the first quarter of 2025, as compared to the same period in 2024, primarily due to higher retail generation sales as a result of colder weather temperatures and lower shopping, which increased sales volumes, partially offset by lower non-shopping generation auction rates. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA in the first quarter of 2025, as compared to the same period of 2024, decreased to 88% from 89% in Ohio and to 60% from 61% in Pennsylvania. Retail and wholesale generation sales revenues have no material impact to earnings.
Operating Expenses —
Total operating expenses increased $96 million, primarily due to:
•Purchased power costs, which have no material impact to earnings, decreased $32 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to lower unit costs and decreased capacity expenses, partially offset by increased generation sales volumes as described above.
•Other operating expenses increased $40 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to:
•Higher network transmission expenses of $29 million, which are deferred for future recovery, resulting in no material impact to earnings;
•Higher planned vegetation management expenses of $5 million, primarily in Pennsylvania as approved and recovering in the base rate case;
•Higher uncollectible expenses of $7 million, which were mostly deferred for future recovery;
•Higher energy efficiency and other state mandated program costs of $19 million, which were deferred for future recovery, resulting in no material impact to earnings; and
•Higher other operating expenses of $11 million, primarily due to severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025.
The increase was partially offset by:
•Lower storm restoration expenses of $30 million, which were deferred for future recovery; and
•Lower maintenance work of $1 million.
•Depreciation expense increased $1 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to a higher asset base.
•Deferral of regulatory assets decreased $69 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to a $69 million net decrease in generation and transmission related deferrals, and a $30 million decrease from lower deferred storm restoration expenses, partially offset by a $10 million net increase in other deferrals, and $20 million of higher amortization expenses resulting from recovery of previously deferred storm costs and customer assistance programs from the implementation of the Pennsylvania base rate case in 2025.
•General taxes increased $18 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to higher property and gross receipts taxes.
Other Expense —
Other expense increased $1 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to lower interest income on regulated money pool investments being offset by lower interest expense as a result of long-term debt redemptions since the first quarter of 2024, partially offset by higher average short-term borrowings.
Income Taxes —
Distribution segment’s effective tax rate was 21.6% and 19.9% for the three months ended March 31, 2025 and 2024, respectively. The increase in the effective tax rate is primarily due to lower tax benefits from state flow-through and an increase in the amortization of excess deferred income taxes.
Integrated Segment — First Quarter of 2025 Compared with First Quarter of 2024
Integrated segment’s earnings attributable to FE increased $54 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to the implementation of base rate cases in New Jersey and West Virginia, higher customer usage and demand, higher revenues from regulated investment programs, lower operating expenses, and the absence of a $53 million charge at JCP&L in connection with the base rate case settlement agreement in the first quarter of 2024, as further discussed below, partially offset by costs associated with the announced organizational changes and the absence of a benefit associated with the approval by the WVPSC to recover costs of certain retired generation stations in the first quarter of 2024.
Revenues —
Integrated’s total revenues increased $254 million as a result of the following sources:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| Revenues by Type of Service |
1 |
2025 |
|
2024 |
|
Increase |
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
| Distribution services |
|
$ |
431 |
|
|
$ |
339 |
|
|
$ |
92 |
|
|
|
|
|
|
|
| Generation sales: |
|
|
|
|
|
|
|
|
|
|
|
|
| Retail |
|
755 |
|
|
632 |
|
|
123 |
|
|
|
|
|
|
|
| Wholesale |
|
47 |
|
|
30 |
|
|
17 |
|
|
|
|
|
|
|
| Total generation sales |
|
$ |
802 |
|
|
$ |
662 |
|
|
$ |
140 |
|
|
|
|
|
|
|
| Transmission revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| JCP&L |
|
61 |
|
|
52 |
|
|
9 |
|
|
|
|
|
|
|
| MP & PE |
|
39 |
|
|
29 |
|
|
10 |
|
|
|
|
|
|
|
| Total transmission revenues |
|
$ |
100 |
|
|
$ |
81 |
|
|
$ |
19 |
|
|
|
|
|
|
|
| Other |
|
16 |
|
|
13 |
|
|
3 |
|
|
|
|
|
|
|
| Total Revenues |
|
$ |
1,349 |
|
|
$ |
1,095 |
|
|
$ |
254 |
|
|
|
|
|
|
|
Distribution services revenues increased $92 million in the first quarter of 2025, as compared to the same period of 2024, primarily resulting from higher customer usage as a result of the colder weather temperatures, higher revenues from the implementation of base rate cases, and higher rider revenues associated with certain regulated investment programs. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.
Generation sales revenues increased $140 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to higher retail revenues and higher wholesale revenues.
•Retail generation sales increased $123 million in the first quarter of 2025, as compared to the same period in 2024 primarily due to higher non-shopping generation auction rates and higher customer usage as a result of the colder weather temperatures. Retail generation sales, other than those in West Virginia, have no material impact to earnings.
•Wholesale generation revenues increased $17 million in the first quarter of 2025, as compared to the same period in 2024, primarily due to higher sales volumes, partially offset by lower wholesale rates. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.
Transmission revenues increased $19 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to a higher rate base from regulated investment programs.
Operating Expenses —
Total operating expenses increased $211 million, primarily due to:
•Fuel costs increased $44 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher unit costs and higher consumption volumes. Due to the ENEC, fuel expense has no material impact to earnings.
•Purchased power costs, which have no material impact to earnings, increased $83 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher unit costs, sales volumes and capacity expenses.
•Other operating expenses decreased $17 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to:
•The absence of a $53 million pre-tax charge at JCP&L in the first quarter 2024 associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the base rate case settlement agreement, to be disallowed from future recovery;
•Lower storm restoration expenses of $4 million, which were mostly deferred for future recovery; and
•Lower other operating expenses of $12 million, primarily due to lower planned regulated generation outage spend and lower maintenance work.
The decrease was partially offset by:
•Higher network transmission expenses of $22 million, which were deferred for future recovery, resulting in no material impact to earnings;
•Higher uncollectible expenses of $5 million, which were mostly deferred for future recovery;
•Higher severance and related costs of $9 million associated with FirstEnergy’s organizational changes announced in the first quarter of 2025; and
•Higher energy efficiency and other state mandated program costs of $16 million, which were deferred for future recovery, resulting in no material impact to earnings.
•Depreciation expense increased $16 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to a higher asset base.
•Deferral of regulatory assets decreased $86 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to the absence of the approval in the first quarter of 2024 to recover $60 million in costs of certain retired generation stations approved by the WVPSC, $16 million in lower deferral of storm related expenses including the absence of the approval in the first quarter of 2024 to recover $11 million in previously included storm costs, and $23 million related to net decreases in other deferrals, partially offset by a $13 million net increase from higher generation and transmission related deferrals.
Other Expense —
Other expense decreased $16 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to the absence of certain nonrecoverable charges recognized in the first quarter of 2024, lower interest expense as a result of lower average short-term borrowings and long-term debt redemptions since the first quarter of 2024, and higher capitalized interest.
Income Taxes —
Integrated segment’s effective tax rate was 22.7% and 29.9% for the three months ended March 31, 2025 and 2024, respectively. The decrease in the effective tax rate is primarily due to the absence of a tax charge related to the expected utilization of NOL carryforwards related to the sale of equity interest in FET in the first quarter of 2024.
Stand-Alone Transmission Segment — First Quarter of 2025 Compared with First Quarter of 2024
Stand-Alone Transmission Segment’s earnings attributable to FE decreased $3 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to the dilutive effect of the FET Equity Interest Sale that closed in March 2024, and the expected elimination of the 50 basis point ROE adder associated with ATSI’s RTO membership as a result of the Sixth Circuit ruling in January 2025, partially offset by the absence of a discrete tax charge related to the FET Equity Interest Sale in the first quarter of 2024 and higher revenues from regulated capital investments that increased rate base.
Revenues —
Stand-Alone Transmission’s total revenues increased $53 million, primarily due to a higher rate base and recovery of higher transmission operating expenses, partially offset by the expected elimination of the 50 basis point ROE adder associated with ATSI’s RTO membership as a result of the Sixth Circuit ruling in January 2025.
The following table shows revenues by transmission asset owner:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| Revenues by Transmission Asset Owner |
1 |
2025 |
|
|
2024 |
|
|
Increase |
|
|
(In millions) |
| ATSI |
|
$ |
265 |
|
|
|
$ |
245 |
|
|
|
$ |
20 |
|
| TrAIL |
|
71 |
|
|
|
68 |
|
|
|
3 |
|
| MAIT |
|
132 |
|
|
|
105 |
|
|
|
27 |
|
| KATCo |
|
23 |
|
|
|
20 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
| Total Revenues |
|
$ |
491 |
|
|
|
$ |
438 |
|
|
|
$ |
53 |
|
Operating Expenses —
Total operating expenses increased $36 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to higher depreciation and property tax expenses from a higher asset base as well as higher operating and maintenance expenses. Nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expense —
Total other expense was flat in the first quarter of 2025, as compared to the same period of 2024, primarily due to higher interest expenses from new debt issuances since the first quarter of 2024, offset by higher capitalized financing costs and the absence of a prior year non-recoverable charge recorded in the first quarter of 2024.
Income Taxes —
Stand-Alone Transmission’s effective tax rate was 22.9% and 38.0% for the three months ended March 31, 2025 and 2024, respectively. The decrease in the effective tax rate is primarily due to the absence of a discrete tax charge related to the FET Equity Interest Sale in the first quarter of 2024.
Corporate / Other — First Quarter 2025 Compared with First Quarter 2024
Financial results at Corporate/Other resulted in a $3 million decrease in losses attributable to FE in the first quarter of 2025, as compared to the same period of 2024, primarily due to:
•$15 million (after-tax) of lower interest expense as a result of the redemption of certain FE long-term debt in 2024 and lower short-term borrowings, and
•The absence of a discrete tax charge related to the PA Consolidation, partially offset by tax benefits related to the utilization of state NOL carryforwards and updates to deferred taxes on the FET Equity Interest Sale, all recorded in the first quarter of 2024.
The decrease in losses were partially offset by:
•$16 million (after-tax) in lower investment earnings related to FEV’s equity method investment in Global Holding.
REGULATORY ASSETS AND LIABILITIES
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Electric Companies and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.
Management assesses the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability relate to changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets and liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
The following table provides information about the composition of FirstEnergy’s net regulatory assets and liabilities as of March 31, 2025, and December 31, 2024, and the changes during the three months ended March 31, 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Regulatory Assets (Liabilities) by Source - FirstEnergy |
|
March 31,
2025 |
|
December 31,
2024 |
|
Change |
| |
|
(In millions) |
| Customer payables for future income taxes |
|
$ |
(2,200) |
|
|
$ |
(2,234) |
|
|
$ |
34 |
|
| Spent nuclear fuel disposal costs |
|
(69) |
|
|
(72) |
|
|
3 |
|
| Asset removal costs |
|
(671) |
|
|
(681) |
|
|
10 |
|
| Deferred transmission costs |
|
152 |
|
|
190 |
|
|
(38) |
|
| Deferred generation costs |
|
462 |
|
|
481 |
|
|
(19) |
|
| Deferred distribution costs |
|
320 |
|
|
287 |
|
|
33 |
|
|
|
|
|
|
|
|
| Storm-related costs |
|
1,021 |
|
|
1,015 |
|
|
6 |
|
|
|
|
|
|
|
|
| Energy efficiency program costs |
|
338 |
|
|
349 |
|
|
(11) |
|
| New Jersey societal benefit costs |
|
86 |
|
|
87 |
|
|
(1) |
|
|
|
|
|
|
|
|
| Vegetation management costs |
|
124 |
|
|
125 |
|
|
(1) |
|
| Other |
|
75 |
|
|
75 |
|
|
— |
|
| Net Regulatory Liabilities included on FirstEnergy’s Consolidated Balance Sheets |
|
$ |
(362) |
|
|
$ |
(378) |
|
|
$ |
16 |
|
The following table provides information about the composition of JCP&L’s net regulatory assets and liabilities as of March 31, 2025, and December 31, 2024, and the changes during the three months ended March 31, 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Regulatory Assets (Liabilities) by Source - JCP&L |
|
March 31,
2025 |
|
December 31,
2024 |
|
Change |
| |
|
(In millions) |
| Customer payables for future income taxes |
|
$ |
(406) |
|
|
$ |
(410) |
|
|
$ |
4 |
|
| Spent nuclear fuel disposal costs |
|
(69) |
|
|
(72) |
|
|
3 |
|
| Asset removal costs |
|
(80) |
|
|
(83) |
|
|
3 |
|
| Deferred transmission costs |
|
(11) |
|
|
(3) |
|
|
(8) |
|
| Deferred generation costs |
|
(5) |
|
|
(12) |
|
|
7 |
|
| Deferred distribution costs |
|
223 |
|
|
206 |
|
|
17 |
|
|
|
|
|
|
|
|
| Storm-related costs |
|
305 |
|
|
310 |
|
|
(5) |
|
|
|
|
|
|
|
|
| Energy efficiency program costs |
|
214 |
|
|
208 |
|
|
6 |
|
| New Jersey societal benefit costs |
|
86 |
|
|
87 |
|
|
(1) |
|
|
|
|
|
|
|
|
| Vegetation management costs |
|
7 |
|
|
7 |
|
|
— |
|
| Other |
|
28 |
|
|
27 |
|
|
1 |
|
| Net Regulatory Assets included on JCP&L’s Balance Sheets |
|
$ |
292 |
|
|
$ |
265 |
|
|
$ |
27 |
|
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. Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.
Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. Generally, the ENEC rate is updated annually.
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 $331 million and $51 million for FE and JCP&L, respectively, are currently being recovered through rates as of March 31, 2025. Approximately $402 million and $41 million for FirstEnergy and JCP&L, respectively, and are currently being recovered through rates as of December 31, 2024.
Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including New Jersey energy efficiency and renewable energy programs, FE PA's Energy Efficiency and Conservation programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland Surcharge. Investments in certain of these energy efficiency programs earn a long-term return.
New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and the New Jersey Clean Energy Program.
Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey, certain distribution and transmission vegetation management costs in West Virginia, and certain transmission vegetation management costs at ATSI (amortized through 2030) and KATCo (amortized through 2036).
The following table provides information about the composition of FirstEnergy’s net regulatory assets that do not earn a current return as of March 31, 2025 and December 31, 2024, of which approximately $794 million and $698 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulatory Assets by Source Not Earning a Current Return - FirstEnergy |
|
March 31,
2025 |
|
December 31,
2024 |
|
Change |
|
|
(In millions) |
|
|
|
|
|
|
|
| Deferred transmission costs |
|
$ |
5 |
|
|
$ |
8 |
|
|
$ |
(3) |
|
| Deferred generation costs |
|
307 |
|
|
314 |
|
|
(7) |
|
| Deferred distribution costs |
|
160 |
|
|
153 |
|
|
7 |
|
|
|
|
|
|
|
|
| Storm-related costs |
|
695 |
|
|
694 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Vegetation management costs |
|
10 |
|
|
16 |
|
|
(6) |
|
| Other |
|
55 |
|
|
58 |
|
|
(3) |
|
| FirstEnergy Regulatory Assets Not Earning a Current Return |
|
$ |
1,232 |
|
|
$ |
1,243 |
|
|
$ |
(11) |
|
The following table provides information about the composition of JCP&L’s net regulatory assets that do not earn a current return as of March 31, 2025 and December 31, 2024, of which approximately $54 million and $45 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulatory Assets by Source Not Earning a Current Return - JCP&L |
|
March 31,
2025 |
|
December 31,
2024 |
|
Change |
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Deferred generation costs |
|
$ |
4 |
|
|
$ |
4 |
|
|
$ |
— |
|
| Deferred distribution costs |
|
109 |
|
|
101 |
|
|
8 |
|
|
|
|
|
|
|
|
| Storm-related costs |
|
306 |
|
|
310 |
|
|
(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Vegetation management costs |
|
7 |
|
|
7 |
|
|
— |
|
| Other |
|
16 |
|
|
17 |
|
|
(1) |
|
| JCP&L Regulatory Assets Not Earning a Current Return |
|
$ |
442 |
|
|
$ |
439 |
|
|
$ |
3 |
|
CAPITAL RESOURCES AND LIQUIDITY
The Registrants’ 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.
The Registrants 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 2025 and beyond, the Registrants 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 the Registrants to, among other things, fund capital expenditures and other capital-like investments, and refinance short-term and maturing long-term debt, subject to market conditions and other factors. FE may utilize instruments other than senior notes to fund its liquidity and capital requirements, including hybrid securities.
In alignment with FirstEnergy’s strategy to invest in its segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated subsidiaries to issue and/or refinance debt.
Any financing plans by FE or any of its 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 subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.
While supply lead times have not fully returned to pre-pandemic levels, FirstEnergy continues to monitor the situation in light of demand increases across the industry, including due to data center usage, and uncertainty around the imposition of tariffs by the U.S. government and retaliatory tariffs that have been, and may be, imposed in response. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, the situation remains fluid and a prolonged continuation or further increase in demand, or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
The U.S. presidential administration has announced the imposition of widespread and substantial tariffs on imports, with additional tariffs to potentially be adopted in the future. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
In January 2025, FirstEnergy executed a lift-out transaction with MetLife, which transferred approximately $640 million of plan assets and $652 million of plan obligations, associated with approximately 2,000 former competitive generation employees, who will assume future and full responsibility to fund and administer their benefit payments. There was no change to the pension benefits for any participant as a result of the transfer and the transaction was funded by pension plan assets. FirstEnergy believes that this lift-out transaction, in addition to the lift-out in 2023, further de-risked potential volatility with the pension plan assets and liabilities, and will continue to evaluate other lift-outs in the future based on market and other conditions.
As of March 31, 2025, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to current portion of long-term debt, accounts payable, short-term borrowings and accrued interest, taxes, and compensation and benefits.
FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below.
As of March 31, 2025, JCP&L’s net deficit in working capital (current assets less current liabilities) was primarily due to current portion of long-term debt, accounts payable, short-term borrowings and accrued interest and compensation and benefits. JCP&L believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs.
Short-Term Borrowings / Revolving Credit Facilities
The credit facilities of FE and certain of its subsidiaries are as follows:
•FE, $1.0 billion revolving credit facility, matures October 18, 2028;
•FET, $1.0 billion revolving credit facility, matures October 20, 2029;
•Ohio Companies, $800 million revolving credit facility, matures October 18, 2028;
•FE PA, $950 million revolving credit facility, matures October 18, 2028;
•JCP&L, $750 million revolving credit facility, matures October 18, 2028;
•MP and PE, $400 million revolving credit facility, matures October 18, 2028;
•ATSI, MAIT and TrAIL, $850 million revolving credit facility, October 18, 2028; and
•KATCo, $150 million revolving credit facility, matures October 20, 2028.
Borrowings under these 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 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 credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 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.
Each of the 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. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on FirstEnergy’s results of operations, cash flows, financial condition and liquidity.
FirstEnergy had $1,635 million and $550 million of outstanding short-term borrowings as of March 31, 2025, and December 31, 2024, respectively. FirstEnergy’s available liquidity from external sources as of April 28, 2025, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revolving Credit Facilities |
|
Maturity |
|
Commitment |
|
Available Liquidity |
|
| |
|
|
|
(In millions) |
|
| FE |
|
October 2028 |
|
$ |
1,000 |
|
|
$ |
347 |
|
|
| FET |
|
October 2029 |
|
1,000 |
|
|
615 |
|
|
| Ohio Companies |
|
October 2028 |
|
800 |
|
|
742 |
|
|
| FE PA |
|
October 2028 |
|
950 |
|
|
931 |
|
|
| JCP&L |
|
October 2028 |
|
750 |
|
|
722 |
|
|
| MP and PE |
|
October 2028 |
|
400 |
|
|
348 |
|
|
| ATSI, MAIT and TrAIL |
|
October 2028 |
|
850 |
|
|
844 |
|
|
| KATCo |
|
October 2028 |
|
150 |
|
|
150 |
|
|
|
|
Subtotal |
|
$ |
5,900 |
|
|
$ |
4,699 |
|
|
| Cash and cash equivalents |
|
— |
|
|
36 |
|
|
|
|
Total |
|
$ |
5,900 |
|
|
$ |
4,735 |
|
|
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 March 31, 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Individual Borrower |
|
Regulatory Debt Limitations |
|
Credit Facility Commitment |
|
Debt-to-Total-Capitalization Ratio |
| |
|
(In millions) |
|
|
|
| FE |
|
|
N/A |
|
|
$ |
1,000 |
|
|
|
N/A(2) |
ATSI(1) |
|
|
$ |
500 |
|
|
|
350 |
|
|
|
38.8 |
% |
CEI(1) |
|
|
500 |
|
|
|
300 |
|
|
|
37.0 |
% |
| FET |
|
|
N/A |
|
|
1,000 |
|
|
|
65.0 |
% |
FE PA(1) |
|
|
1,250 |
|
|
|
950 |
|
|
|
49.3 |
% |
JCP&L(1) |
|
|
1,500 |
|
|
|
750 |
|
|
|
32.8 |
% |
KATCo(1) |
|
|
200 |
|
|
|
150 |
|
|
|
30.1 |
% |
MAIT(1) |
|
|
400 |
|
|
|
350 |
|
|
|
38.2 |
% |
MP(1) |
|
|
500 |
|
|
|
250 |
|
|
|
50.6 |
% |
OE(1) |
|
|
500 |
|
|
|
300 |
|
|
|
53.5 |
% |
PE(1) |
|
|
150 |
|
|
|
150 |
|
|
|
46.5 |
% |
TE(1) |
|
|
300 |
|
|
|
200 |
|
|
|
47.5 |
% |
TrAIL(1) |
|
|
400 |
|
|
|
150 |
|
|
|
38.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Regulatory debt limitations include amounts which may be borrowed under the regulated companies’ money pool.
(2) FE is not required to maintain a debt-to-total-capitalization ratio under its credit facility. 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 ended December 31, 2021. FE's consolidated interest coverage ratio as of March 31, 2025, was approximately 4.9 times.
Subject to each borrower’s sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the 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 credit facilities and against the applicable borrower’s borrowing sublimit. As of March 31, 2025, FirstEnergy had $177 million in outstanding LOCs, $146 million of which are issued under the revolving credit facilities.
|
|
|
|
|
|
|
|
|
|
|
|
| Revolving Credit Facility |
|
LOC Availability as of March 31, 2025 |
LOC Utilized as of March 31, 2025 |
|
|
(In millions) |
| FE |
|
$ |
100 |
|
$ |
3 |
|
| FET |
|
100 |
|
— |
|
| Ohio Companies |
|
150 |
|
38 |
|
| FE PA |
|
200 |
|
19 |
|
| JCP&L |
|
100 |
|
28 |
|
| MP and PE |
|
100 |
|
52 |
|
| ATSI, MAIT and TrAIL |
|
200 |
|
6 |
|
| KATCo |
|
35 |
|
— |
|
|
|
|
|
Each of the 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 credit facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 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 March 31, 2025, FE was in compliance with its applicable consolidated interest coverage ratio and the borrowers, in each case as defined under the credit facilities, were in compliance with their debt-to-total-capitalization ratio covenants.
FirstEnergy Money Pools
FirstEnergy’s regulated operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Effective September 23, 2024, AGC and KATCo became participants in the regulated companies’ money pool. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. As of June 1, 2024, FET no longer participated in the unregulated money pool. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average Interest Rates |
Regulated Companies’ Money Pool |
|
Unregulated Companies’ Money Pool |
|
2025 |
|
2024 |
|
2025 |
|
2024 |
| For the Three Months Ended March 31, |
4.93 |
% |
|
6.32 |
% |
|
5.44 |
% |
|
7.08 |
% |
|
|
|
|
|
|
|
|
Long-Term Debt Capacity
FE’s and its subsidiaries’ access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of April 28, 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate Credit Rating |
|
Senior Secured |
|
Senior Unsecured |
|
Outlook/Credit/Watch(1) |
| Issuer |
|
S&P |
|
Moody’s |
|
Fitch |
|
S&P |
|
Moody’s |
|
Fitch |
|
S&P |
|
Moody’s |
|
Fitch |
|
S&P |
|
Moody’s |
|
Fitch |
| FE |
|
BBB |
|
Baa3 |
|
BBB |
|
— |
|
— |
|
— |
|
BBB- |
|
Baa3 |
|
BBB |
|
P |
|
S |
|
S |
|
| Distribution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| CEI |
|
BBB |
|
Baa3 |
|
BBB+ |
|
— |
|
— |
|
— |
|
BBB |
|
Baa3 |
|
A- |
|
P |
|
S |
|
P |
| OE |
|
BBB+ |
|
A3 |
|
BBB+ |
|
A |
|
A1 |
|
A |
|
BBB+ |
|
A3 |
|
A- |
|
P |
|
S |
|
P |
| TE |
|
BBB+ |
|
Baa2 |
|
BBB+ |
|
A |
|
A3 |
|
A |
|
— |
|
— |
|
— |
|
P |
|
S |
|
P |
| FE PA |
|
BBB+ |
|
A3 |
|
BBB+ |
|
A |
|
A1 |
|
— |
|
BBB+ |
|
A3 |
|
A- |
|
P |
|
S |
|
P |
|
| Integrated: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| JCP&L |
|
BBB |
|
A3 |
|
A- |
|
— |
|
— |
|
— |
|
BBB |
|
A3 |
|
A |
|
P |
|
S |
|
S |
| MP |
|
BBB |
|
Baa2 |
|
A- |
|
A- |
|
A3 |
|
A+ |
|
BBB |
|
Baa2 |
|
— |
|
S |
|
S |
|
S |
| AGC |
|
BBB- |
|
Baa2 |
|
A- |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
S |
|
S |
|
S |
| PE |
|
BBB |
|
Baa2 |
|
BBB+ |
|
A- |
|
A3 |
|
A |
|
— |
|
— |
|
— |
|
S |
|
S |
|
S |
|
| Stand-Alone Transmission: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FET |
|
A- |
|
Baa2 |
|
BBB+ |
|
— |
|
— |
|
— |
|
BBB+ |
|
Baa2 |
|
BBB+ |
|
P |
|
S |
|
S |
| ATSI |
|
A- |
|
A3 |
|
A |
|
— |
|
— |
|
— |
|
A- |
|
A3 |
|
A+ |
|
P |
|
S |
|
S |
| MAIT |
|
A- |
|
A3 |
|
A |
|
— |
|
— |
|
— |
|
A- |
|
A3 |
|
A+ |
|
P |
|
S |
|
S |
| TrAIL |
|
A- |
|
A3 |
|
A |
|
— |
|
— |
|
— |
|
A- |
|
A3 |
|
A+ |
|
P |
|
S |
|
S |
| KATCo |
|
— |
|
A3 |
|
A- |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
S |
|
S |
(1) S = Stable, P = Positive
The applicable undrawn and drawn margin on the credit facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments under the 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 FE's credit facility. As of March 31, 2025, FirstEnergy could incur approximately $1.1 billion of incremental interest expense or incur a $2.7 billion reduction to the consolidated interest coverage earnings numerator, as defined under the covenant, and FE would remain within the limitations of the financial covenant requirements of FE's credit facility.
Cash Requirements and Commitments
FirstEnergy has certain obligations and commitments to make future payments under contracts. For an in-depth discussion of FirstEnergy’s cash requirements and commitments, see “Capital Resources and Liquidity - Cash Requirements and Commitments" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" within FirstEnergy’s Form 10-K for the year ended December 31, 2024 (filed on February 27, 2025).
Changes in Cash Position
As of March 31, 2025, FirstEnergy had $132 million of cash and cash equivalents and $31 million of restricted cash as compared to $111 million of cash and cash equivalents and $43 million of restricted cash as of December 31, 2024, on the Consolidated Balance Sheets.
The following table summarizes the major classes of cash flow items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| (In millions) |
|
2025 |
|
2024 |
|
Change |
|
|
|
|
|
|
|
| Net cash provided from (used for) operating activities |
|
$ |
637 |
|
|
$ |
(40) |
|
|
$ |
677 |
|
| Net cash used for investing activities |
|
(1,093) |
|
|
(870) |
|
|
(223) |
|
| Net cash provided from financing activities |
|
465 |
|
|
1,646 |
|
|
(1,181) |
|
| Net change in cash, cash equivalents, and restricted cash |
|
9 |
|
|
736 |
|
|
(727) |
|
|
|
|
|
|
|
|
| Cash, cash equivalents, and restricted cash at beginning of period |
|
154 |
|
|
179 |
|
|
(25) |
|
| Cash, cash equivalents, and restricted cash at end of period |
|
$ |
163 |
|
|
$ |
915 |
|
|
$ |
(752) |
|
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, 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 $637 million in the first three months of 2025, as compared to net cash used for operating activities of $40 million in the first three months of 2024. The increase in cash provided from operating activities in 2025, compared to the same period of 2024, is primarily due to:
•Higher revenues from the implementation of base rate cases in Pennsylvania, New Jersey, and West Virginia;
•Higher return on regulated capital investment programs;
•Higher receipts of cash collateral associated with certain generation suppliers that serve shopping customers;
•Increased customer usage and demand as a result of the colder weather temperatures; and
•Lower employee benefit payments.
Cash Flows From Investing Activities
Cash used for investing activities in the first three months of 2025 principally represented cash used for capital investments. The following table summarizes investing activities for the first three months of 2025 and 2024:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| Investing Activities |
|
2025 |
|
2024 |
|
Change |
|
|
(In millions) |
| Capital investments: |
|
|
|
|
|
|
| Distribution Segment |
|
$ |
265 |
|
|
$ |
215 |
|
|
$ |
50 |
|
| Integrated Segment |
|
395 |
|
|
313 |
|
|
82 |
|
| Stand-Alone Transmission Segment |
|
314 |
|
|
258 |
|
|
56 |
|
| Corporate / Other |
|
31 |
|
|
4 |
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Asset removal costs |
|
84 |
|
|
78 |
|
|
6 |
|
| Other |
|
4 |
|
|
2 |
|
|
2 |
|
|
|
$ |
1,093 |
|
|
$ |
870 |
|
|
$ |
223 |
|
|
|
|
|
|
|
|
Cash used for investing activities for the first three months of 2025 increased $223 million, compared to the same period of 2024, primarily due to capital investments.
Cash Flows From Financing Activities
In the first three months of 2025 and 2024, cash provided from financing activities was $465 million and $1,646 million, respectively. The following table summarizes financing activities for the first three months of 2025 and 2024:
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For the Three Months Ended March 31, |
| Financing Activities |
|
2025 |
|
2024 |
|
Change |
| |
|
(In millions) |
|
|
|
|
|
|
|
|
|
| New Issues: |
|
|
|
|
|
|
| Unsecured notes |
|
$ |
— |
|
|
$ |
150 |
|
|
$ |
(150) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
— |
|
|
$ |
150 |
|
|
$ |
(150) |
|
|
|
|
|
|
|
|
| Redemptions / Repayments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Unsecured notes |
|
$ |
(300) |
|
|
$ |
— |
|
|
$ |
(300) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Senior secured notes |
|
(24) |
|
|
(23) |
|
|
(1) |
|
| |
|
$ |
(324) |
|
|
$ |
(23) |
|
|
$ |
(301) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Short-term borrowings, net |
|
$ |
1,085 |
|
|
$ |
(525) |
|
|
$ |
1,610 |
|
| Proceeds from FET Equity Interest Sale |
|
— |
|
|
2,300 |
|
|
(2,300) |
|
| Noncontrolling interest cash distributions |
|
(24) |
|
|
(8) |
|
|
(16) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Common stock dividend payments |
|
(245) |
|
|
(235) |
|
|
(10) |
|
| Debt issuance and redemption costs, and other |
|
(27) |
|
|
(13) |
|
|
(14) |
|
|
|
$ |
465 |
|
|
$ |
1,646 |
|
|
$ |
(1,181) |
|
FirstEnergy had the following issuances and redemptions during the three months ended March 31, 2025 (JCP&L had no issuances or redemptions):
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| Company |
Type |
Redemption / Issuance Date |
Interest Rate |
Maturity |
Amount
(In millions)
|
Description |
| Redemptions |
|
|
|
|
|
|
|
| FE |
Unsecured Notes |
March, 2025 |
2.05% |
2025 |
$300 |
FE redeemed unsecured notes that became due. |
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On April 16, 2025, TrAIL issued $600 million of senior notes due 2031 at 5.00%. Proceeds are expected to be used to redeem senior notes that will be coming due in 2025 and repay short-term borrowings, as well as to fund capital investments, working capital and other corporate purposes.
On December 5, 2024, JCP&L issued $700 million of unsecured senior notes due in 2035 in a private offering that included a registration rights agreement in which JCP&L agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act. On April 1, 2025, JCP&L filed a registration statement on Form S-4 with the SEC, which became effective on April 11, 2025.
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.
FIRSTENERGY - 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 March 31, 2025, outstanding guarantees and other assurances aggregated approximately $1.1 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($651 million) and other assurances of ($440 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 March 31, 2025, $177 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $66 million of net cash collateral as of March 31, 2025, 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 March 31, 2025:
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|
|
|
|
|
| Potential Collateral Obligations |
|
|
|
|
|
Electric Companies and Transmission Companies |
|
FE |
|
Total |
|
|
|
(In millions) |
| Contractual obligations for additional collateral |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Upon downgrade |
|
|
|
|
|
$ |
71 |
|
|
$ |
1 |
|
|
$ |
72 |
|
|
|
|
|
|
|
|
|
|
|
|
Surety bonds (collateralized amount)(1) |
|
|
|
|
|
102 |
|
|
193 |
|
|
295 |
|
| Total Exposure from Contractual Obligations |
|
|
|
|
|
$ |
173 |
|
|
$ |
194 |
|
|
$ |
367 |
|
(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 $38 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
JCP&L - GUARANTEES AND OTHER ASSURANCES
JCP&L has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include stand-by LOCs and surety bonds. JCP&L 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 JCP&L could be required to make under these guarantees as of March 31, 2025, was $48 million.
Collateral and Contingent-Related Features
In the normal course of business, JCP&L 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 JCP&L to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon JCP&L's credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
JCP&L has posted $28 million of collateral in the form of LOCs as of March 31, 2025. JCP&L is holding $21 million of net cash collateral as of March 31, 2025, from certain generation suppliers, and such amount is included in "Other current liabilities" on JCP&L's Balance Sheets.
These credit-risk-related contingent features stipulate that if JCP&L 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 March 31, 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Potential Collateral Obligations |
|
|
|
|
|
JCP&L |
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
| Contractual obligations for additional collateral |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Upon downgrade |
|
|
|
|
|
$ |
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Surety bonds (collateralized amount)(1) |
|
|
|
|
|
20 |
|
|
|
|
|
| Total Exposure from Contractual Obligations |
|
|
|
|
|
$ |
58 |
|
|
|
|
|
(1) Surety bonds are not tied to a credit rating, and their impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $1 million as of March 31, 2025 of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Enterprise Risk Management Committee, comprised of members of senior management, provides general oversight for risk management activities throughout FirstEnergy, including market risk.
Commodity Price Risk
FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, coal and energy transmission.
The valuation of derivative contracts is based on observable market information. See Note 6, “Fair Value Measurements,” of the Combined Notes to Financial Statements of the Registrants for additional details on FirstEnergy’s FTRs.
Equity Price Risk
As of March 31, 2025, the FirstEnergy pension plan assets were allocated approximately as follows: 28% in equity securities, 21% in fixed income securities, 5% in alternatives, 10% in real estate, 23% in private debt/equity, 12% in derivatives and 1% in cash and short-term securities. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027, which, based on various assumptions, including an expected rate of return on assets of 8.5% for 2025, is expected to be approximately $300 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily. JCP&L is not expected to make a contribution.
As of March 31, 2025, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 54% in equity securities, 42% in fixed income securities and 4% in cash and short-term securities. See Note 4, “Pension and Other Post-Employment Benefits,” of the Combined Notes to Financial Statements of the Registrants for additional details on FirstEnergy’s pension and OPEB plans.
In the three months ended March 31, 2025, FirstEnergy’s pension plan assets have gained approximately 3.3% as compared to an annual expected return on plan assets of 8.5%. In the three months ended March 31, 2025, FirstEnergy’s qualified OPEB plan assets have lost approximately 0.9% as compared to an annual expected return on plan assets of 7.0%.
Interest Rate Risk
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension and OPEB costs for 2025, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market.
FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of March 31, 2025, the spot rate was 5.57% and 5.42% for pension and OPEB obligations, respectively, as compared to 5.72% and 5.60% as of December 31, 2024, respectively.
The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2025.
Each of the 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.
Economic Conditions
While supply lead times have not fully returned to pre-pandemic levels, FirstEnergy continues to monitor the situation in light of demand increases across the industry, including due to data center usage, and uncertainty around the imposition of tariffs by the U.S. government and retaliatory tariffs that have been, and may be, imposed in response. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, the situation remains fluid and a prolonged continuation or further increase in demand, or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
The U.S. presidential administration has announced the imposition of widespread and substantial tariffs on imports, with additional tariffs to potentially be adopted in the future. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on the Registrants’ 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
The IRA of 2022, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. The IRA of 2022 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. On September 12, 2024, the U.S. Treasury issued proposed regulations for the AMT for comments. FirstEnergy is assessing the proposed regulations but continues to believe that it is more likely than not that it will be subject to AMT, however, the completion of the U.S. Treasury’s rulemaking process and the future issuance of final regulations, as well as potential future federal tax legislation or presidential executive orders, could significantly change FirstEnergy’s AMT estimates or its conclusion as to whether it is an AMT payer at all. JCP&L is party to an intercompany income tax allocation agreement with FirstEnergy and, accordingly, may be allocated a share of any AMT paid by the FirstEnergy consolidated group. As further discussed below, FirstEnergy expects to pay regular federal corporate income tax for the 2024 tax year, due in large part to the gain realized from closing the FET Equity Interest Sale. The regulatory treatment of the IRA of 2022 may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in the IRA of 2022, 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.
STATE REGULATION
Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
MARYLAND
PE operates under MDPSC approved distribution base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program, following passage of the Climate Solutions Now Act of 2022, required annual incremental energy efficiency targets of 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally, at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million, which the MDPSC approved on December 27, 2024. PE recovers EmPOWER Maryland program costs with carrying costs on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Lost distribution revenue attributable to energy efficiency or demand reduction is recovered only through base rates. Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 67% of its EmPOWER Maryland program costs in 2025, and 100% in 2026 and beyond. All previously unamortized costs for prior cycles are to be collected by the end of 2030, consistent with the 2024-2026 order issued on December 29, 2023. New legislation which took effect on July 1, 2024 is expected to reduce the carrying costs on the EmPOWER unamortized balances for PE by a total of $25 to $30 million over the period of 2024-2030. On July 31, 2024, the MDPSC issued an order implementing revised EmPOWER surcharge rates for PE in accordance with the new law, denying PE’s request for a hearing that sought to challenge certain portions of the law. On August 30, 2024, PE filed a petition seeking judicial review of its challenge to the law in the Circuit Court for Washington County, Maryland. Legal memoranda were filed in December 2024 through February 2025 and a hearing was held on March 7, 2025.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L and one other party filed comments on July 31, 2023.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. On January 30, 2025, and February 25, 2025, Shell New Energies and EDF Renewables North America respectively announced that each was exiting its Atlantic Shores partnership to construct wind energy off the shore of New Jersey. These cancellations do not directly affect JCP&L’s awarded projects, and JCP&L remains under an obligation to begin construction in 2025 based on current NJBPU direction. JCP&L continues to monitor the situation and is engaging state officials about impacts of these announcements to its transmission projects.
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 DOE to finance a substantial portion of the project using low-interest rate loans available under the DOE’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024, which was approved on May 17, 2024. The DOE Loan Program Office has initiated a due diligence review of the application, which is ongoing. On January 16, 2025, the DOE announced a conditional commitment to JCP&L for a loan guarantee of up to approximately $716 million for the project. While this conditional commitment represents a significant milestone and demonstrates the DOE’s intent to finance the project, certain technical, legal, environmental and financial conditions, including negotiation of definitive financing documents, must be satisfied before funding of the loan.
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. On April 10, 2025, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s amended EnergizeNJ petition, which the NJBPU approved on April 23, 2025. The settlement provides for total program costs of $339 million, including capital investments in JCP&L’s electric distribution system of approximately $203 million, $132 million of matching capital investment and approximately $4 million of O&M expense. Pursuant to the settlement, the program would begin on July 1, 2025, and continue through December 31, 2028, and JCP&L has agreed to file a base rate case no later than January 1, 2030.
OHIO
The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. From June 1, 2024, until January 31, 2025, the Ohio Companies operated under ESP V, as modified by the PUCO, and as further described below. On December 18, 2024, the PUCO approved the Ohio Companies’ notice to withdraw ESP V and approved the Ohio Companies’ proposal for returning to ESP IV, with modifications.
ESP IV, as modified, continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with an annual revenue cap of $390 million. In addition, ESP IV, as modified, includes: (1) continuation of a base distribution rate freeze until ESP VI becomes effective or the Ohio Companies’ obtain the PUCO’s staff agreement; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $6.39 million per year to: (a) fund energy conservation, economic development and job retention programs in the Ohio Companies’ service territories; and (b) establish fuel-funds in each of the Ohio Companies’ service territories to assist low-income customers.
On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which became effective June 1, 2024, and would have continued through May 31, 2029. ESP V, as modified by the PUCO, provided for, among other things, the continuation of existing riders related to purchased power, transmission and uncollectibles, the continuation of the DCR rider with proposed annual revenue cap increases until new base rates are established, the continuation of the AMI rider, and the addition of new riders for recovery of storm and vegetation management expenses. Many of the terms and conditions were to be reconsidered in the base rate case. The ESP V order additionally directed the Ohio Companies to file another base distribution rate case not later than May 31, 2028, and contribute $32.5 million during the term of ESP V to fund low-income customer bill assistance programs and bill assistance for income-eligible senior citizens, and to develop an electric vehicle education program to assist customers in transitioning to electric vehicles which was recognized in the second quarter of 2024 within “Other operating expenses” at the Regulated Distribution segment and on FirstEnergy’s Consolidated Statements of Income. Due to the risks and uncertainty resulting from the Ohio Companies’ application for rehearing being denied by operation of law, on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. On December 18, 2024, the PUCO approved the Ohio Companies’ notice of withdrawal. Also on December 18, 2024, the PUCO approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. Consistent with ESP IV, the PUCO authorized the Ohio Companies’ reinstatement of the DCR rider, with an annual revenue cap of $390 million, and denied the Ohio Companies’ request to continue ESP IV’s DCR rider revenue cap increases of $15 million per year. Additionally, the PUCO ordered that storm costs deferred under ESP V since June 1, 2024, remain on the Ohio Companies’ books and subject to review in a future case. The PUCO also denied the Ohio Companies’ request to lift the base rate freeze in ESP IV, permitting the Ohio Companies’ pending base rate case to continue, but prohibiting new rates from going into effect until either the effective date of ESP VI, or the staff agrees that the freeze be lifted and new rates be implemented. On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV. On March 14, 2025, the Ohio Companies filed with the PUCO a request to commence its quadrennial review of ESP IV and establish the proposed schedule. The request remains pending before the PUCO. On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV.
On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI, for a term beginning on the date new base distribution rates from the pending base rate case go into effect, in an effort to align with the ongoing base distribution rate case, and continuing through May 31, 2028. ESP VI proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, and proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual reliability performance-based revenue cap increases of $37 million to $43 million, and an AMI rider for recovery of approved grid modernization investments. ESP VI additionally proposes riders to support continued maintenance of the distribution system, including recovery of vegetation management and storm restoration operations and maintenance expenses. In addition, ESP VI proposes energy efficiency programs for low-income customers, and includes a commitment to spend $6.5 million annually over the ESP VI term, without recovery from customers, on initiatives to assist low-income customers, as well as education and incentives to help ensure customers have good experiences with electric vehicles. The PUCO held a technical conference on March 12, 2025.
On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million, with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual amount each year using this method. Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony. On July 31, 2024, the Ohio Companies filed an update that adjusted the net increase in base distribution revenues to approximately $190 million and incorporated matters in the rate case as directed by the PUCO’s ESP V order. On January 27, 2025, the Ohio Companies filed a notice in the base rate case notifying parties that they will update their application for an increase in base distribution rates to reflect the withdrawal of ESP V and the reversion to ESP IV. The PUCO Staff hired a third-party to assist in the review of the Ohio Companies' base rate case filing, and on February 21, 2025, PUCO staff and the third party auditor each filed their reports. The auditor’s report recommended adjustments which would result in a net increase of the Ohio Companies’ base distribution revenues of approximately $8 million, with a return on equity of 9.63% and capital structures of 48.8% debt and 51.2% equity for each of the Ohio Companies. PUCO staff’s report takes limited positions on the auditor’s finding and recommendations and makes additional findings. On March 24, 2025, the Ohio Companies, OCC, and other parties filed objections to the PUCO’s staff report and the auditor’s report. In addition, the Ohio Companies filed certain pieces of supplemental testimony and intervenors filed direct testimony.
The Ohio Companies and various parties are engaged in settlement discussions with respect to the pending base rate case. Evidentiary hearings are scheduled to begin May 5, 2025.
On May 16, 2022, May 15, 2023, and May 15, 2024, the Ohio Companies filed their SEET applications for determination of the existence of significantly excessive earnings under ESP IV for calendar years 2021, 2022, and 2023, respectively. Each application demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. These matters remain pending before the PUCO.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below and on November 22, 2024, the administrative law judge ordered that the bifurcated portion of the corporate separation audit, discussed further below, be consolidated with the already-consolidated DMR audit and expanded DCR rider audit proceeding. Evidentiary hearings are scheduled to begin June 10, 2025.
On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directed the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the DCR rider audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and the stay was lifted on February 26, 2024. On September 30, 2024, the third-party auditor’s report was filed. The audit examined 53 payments totaling approximately $75 million made in support of the passage of HB 6 and subsequent referendum efforts, and concluded that less than $5 million was allocated to the Ohio Companies. The audit report affirmed the Ohio Companies’ conclusion in its August 6, 2021, filing that a rate impact of less than $15 thousand was charged to the Ohio Companies’ pole attachment customers associated with political and charitable spending in support of HB 6. On October 22, 2024, parties filed comments on the audit report, and on November 5, 2024, parties filed reply comments. The parties' comments remain pending with the PUCO.
In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and the stay was lifted on February 26, 2024. On September 10, 2024, the Ohio Companies filed testimony describing their compliance with Ohio corporate separation laws and the implementation of the recommendations made in the audit reports. On September 20, 2024, intervenors filed testimony recommending fines for alleged violations of the Ohio corporate separation requirements. Evidentiary hearings were held on October 9 and 10, 2024; the scope of the hearings excluded allegations involving activities related to the passage of HB 6 and the former PUCO chairman, which will be addressed at a later time.
Initial and reply briefs have been filed by the Ohio Companies, PUCO staff and the intervening parties. To the extent the PUCO ultimately accepts the intervenors’ recommendations and issues a fine to the Ohio Companies, such amount is not expected to be material.
On September 3, 2024, the Ohio Companies filed an application to amend their corporate separation plan to incorporate certain recommendations from prior audit reports, which include, but are not limited to, improving controls for non-regulated competitive employees’ physical space and access to data, updating and implementing a process to annually review the cost allocation manual, developing state specific codes of conduct practices, and implementing additional training related to the cost allocation manual and the state codes of conduct. On October 23, 2024, the administrative law judge issued an entry suspending automatic approval of the amended corporate separation plan and establishing a procedural schedule.
In connection with an ongoing annual audit of the Ohio Companies’ DCR rider for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through the DCR rider or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and the stay was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, and further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement. On November 22, 2024, the administrative law judge ordered that the bifurcated portion of the corporate separation audit be consolidated with the already-consolidated DMR audit and the expanded DCR rider audit proceeding. Evidentiary hearings are scheduled to begin June 10, 2025.
On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023, entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing. As the PUCO did not rule on OCC’s November 17, 2023, application for rehearing within 30 days of filing, the application for rehearing was denied by operation of law.
In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.
See below for additional details on the government investigations and ongoing litigation surrounding the investigation of HB 6.
PENNSYLVANIA
FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025. FE PA operates under rates approved by the PPUC, effective as of January 1, 2025.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.
Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for accelerated infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs.
On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the 2025-2029 phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period. The PPUC approved FE PA’s application on December 19, 2024, and implementation began in January 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective March 27, 2024. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually and MP and PE will file their next ENEC filing on or before September 1, 2025, for rates effective January 1, 2026.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. 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, and two of the five solar generation sites went into service in 2024. On December 4, 2024, MP and PE submitted for approval a settlement agreement to increase its solar surcharge rate. The WVPSC approved the settlement without modification on December 27, 2024, and new rates went into effect on January 1, 2025.
FERC REGULATORY MATTERS
Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015, through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy 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 reclassified certain transmission capital assets to operating expenses for the audit period. FirstEnergy fully recovered approximately $105 million ($13 million at JCP&L) of these costs reclassified to operating expenses in its transmission formula rate revenue requirements as of December 31, 2024. Furthermore, the Ohio Companies are in the process of addressing the outcomes of the FERC Audit with the PUCO, which includes seeking continued rate base treatment of approximately $99 million of certain corporate support costs allocated to distribution capital assets as of March 31, 2025.
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. On July 5, 2024, and September 26, 2024, the FERC Office of Enforcement issued additional data requests related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. On September 10, 2024, and January 13, 2025, the FERC Office of Enforcement issued further data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy responded. If the FERC Office of Energy Market Regulation and the FERC Office of Enforcement were to successfully challenge the recovery of the 2022 reclassified operating expenses and formula transmission rates it could have material adverse effect on FirstEnergy financial conditions, result of operations, and cash flows.
Transmission ROE Incentive
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. On January 17, 2025, the Sixth Circuit ruled that the 50 basis point adder is available only where RTO membership is voluntary, that Ohio law requires Ohio’s transmission utilities to be members of an RTO, and that it was unlawful for FERC to excise the adder from AEP rates, but not from the Duke and ATSI rates. During 2024, as a result of the ruling, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the Consolidated Statements of Income and Comprehensive Income at the Stand-Alone Transmission segment, to reflect the expected refund owed to transmission customers back to February 24, 2022. On March 3, 2025, FirstEnergy filed for rehearing en banc, and Duke and AEP also filed for rehearing, which was denied by the Sixth Circuit on March 26, 2025. On April 16, 2025, the Sixth Circuit agreed to hold the case pending further appeal to the Supreme Court of the U.S. The deadline to file for review at the Supreme Court of the U.S. is June 25, 2025.
Transmission ROE Methodology
A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 and remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis; provided however, due to the Sixth Circuit’s ruling in the Transmission ROE Incentive matter described above, ATSI is collecting the ROE incentive adder subject to refund.
Transmission Planning Supplement Projects
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. Subsequently, intervenors expanded the scope of this proceeding to all of the transmission utilities in PJM, including JCP&L. ATSI and the other transmission utilities in Ohio and PJM filed comments.
Local Transmission Planning Complaint
On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates.
The complaint demands that FERC: (i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100kV or higher, (ii) appoint “independent transmission monitors” to conduct such planning, and (iii) condition construction of local transmission facilities on the facility having been planned by the “independent transmission monitor.” FirstEnergy is participating in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. FirstEnergy, together with the PJM transmission owners, filed a motion to dismiss the complaint on March 20, 2025, which is pending before FERC. FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy and its transmission capital investment strategy.
Ghiorzi v. PJM
In December 2023, PJM assigned certain baseline RTEP projects to NextEra Energy Transmission, which subsequently informed PJM that it would not construct the projects. On April 3, 2025, following the reassignment by PJM of certain baseline RTEP projects in Maryland and Virginia to PE, two individuals filed a complaint at FERC challenging this outcome. The complainants assert that PJM erred in reassigning the work to PE because such reassignment projects: (i) did not reflect the cost estimates or cost caps included in NextEra Energy Transmission’s bid and (ii) would be constructed with different routing than as originally proposed. FERC set May 7, 2025, as the deadline for intervention and comment. PE has intervened and plans to submit comments on May 7, 2025. FirstEnergy and PE are unable to predict the outcome or estimate the impact that this complaint may have.
Valley Link Formula Transmission Rate
Valley Link is a joint venture between FET, AEP and Dominion, and was formed to submit applications to construct transmission solutions to identified transmission reliability issues. In 2024, Valley Link submitted a portfolio of transmission solutions to the reliability issues that were the subject of the PJM 2024 RTEP Window 1 planning process. On February 26, 2025, PJM selected approximately $3.0 billion of the transmission solutions proposed by Valley Link for construction through PJM’s “baseline” RTEP process. On March 14, 2025, the Valley Link joint venture filed an application for forward-looking formula transmission rates to provide for cost recovery for the portfolio of selected projects. Among other things, the transmission rate application provides for a capital structure of 40% debt and 60% equity, and a base ROE of 10.9% with associated templates and protocols, as well as transmission rate incentives, including the abandonment rate incentive, the construction work in progress rate incentive, the RTO participation adder incentive, the hypothetical capital structure incentive, and the regulatory asset incentive. On April 4, 2025, certain parties filed protests of certain elements of the proposed formula rate and requested transmission incentives, to which Valley Link responded on April 21, 2025. On April 8, 2025, PJM also sought to intervene in the matter. FERC is expected to issue an initial order by May 13, 2025.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate the Registrants with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While the Registrants’ 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. The Registrants 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 their business, results of operations, cash flows and financial condition. In general, environmental requirements applicable to the electric power sector are becoming increasingly prescriptive and stringent, and the EPA finalized a number of rules in 2024 that could impact the Registrants. However, the Trump administration has issued certain executive orders and stated its intention to rescind, revise or replace some existing environmental regulations and the ultimate impact of recently finalized rules, several of which are in litigation, and any replacement rules are uncertain.
On March 12, 2025, the EPA announced its intent to reevaluate or reconsider numerous environmental regulations, many of which apply to the Registrants. The specific timing or outcome of this initiative remains unknown, but regular required rulemaking processes and procedures still apply, and litigation is also anticipated to occur. The following disclosures do not attempt to discern potential impacts of these deregulatory actions until and unless formal rulemaking or other regulatory actions are announced and the potential impacts to operations can be discerned.
The disclosures below apply to FirstEnergy and the disclosures under “Regulation of Waste Disposal,” are also applicable to JCP&L.
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 Supreme Court of the U.S. ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.
Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the Supreme Court of the U.S. Oral argument was heard on February 21, 2024. On June 27, 2024, the Supreme Court of the U.S. granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. On February 6, 2025, the EPA filed a motion at the D.C. Circuit to hold the proceedings in abeyance for 60 days to allow the EPA time to familiarize itself with the Good Neighbor Plan and in particular, time to brief the new administration about these consolidated petitions and the underlying Rule to allow them to decide what action, if any, is necessary. On February 21, 2025, the D.C. Circuit denied the EPA’s motion and scheduled oral argument on the merits for April 25, 2025. On March 10, 2025, the EPA filed a motion for remand with the D.C. Circuit identifying issues with the Good Neighbor Plan that make reconsideration appropriate. The D.C. Circuit granted the motion for remand and cancelled oral argument. Consistent with its March 12, 2025, announcement, the EPA intends to undertake reconsideration of the rule and complete any new rulemaking by Fall 2026.
Climate Change
In recent years, certain regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. At the federal level, presidential administrations have held differing views on prioritizing actions to address GHG emissions and, by extension, climate change. Those differing views have led to policy changes, creating uncertainty about environmental requirements and associated impacts.
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 Supreme Court of the U.S. stayed the rule during the pendency of the challenges to the D.C. Circuit and Supreme Court of the U.S. 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 Supreme Court of the U.S. in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration.
In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule in the D.C. Circuit. On July 19, 2024, the D.C. Circuit denied the stay motions and on July 23 and 26, 2024 the aggrieved petitioners filed emergency stay applications to the Supreme Court of the U.S. On October 16, 2024, the Supreme Court of the U.S. denied the stay applications. On December 6, 2024, oral arguments on the merits of the challenge were heard by the D.C. Circuit. On February 5, 2025, the Department of Justice filed an unopposed motion on behalf of EPA in the D.C. Circuit, seeking to hold the litigation in abeyance, and forego issuing its opinion, for a period of 60 days while the new leadership at EPA evaluates the rule and determines how it wishes to proceed On February 19, 2025, the D.C. Circuit granted EPA’s motion.
Most recently, among other deregulatory actions, Executive Order 14514 directs the Administrator of the EPA to make recommendations on the “legality and continuing applicability” of the 2009 Endangerment Finding, which forms the basis for the EPA's GHG regulations. On March 12, 2025, the EPA announced a series of planned deregulatory actions that it would be taking related to such executive order, including reconsideration of the regulations to limit power plant GHG emissions. Depending on the outcome of any appeals and the EPA review, compliance with the GHG emissions limits could require additional capital expenditures or changes in operation at the Fort Martin and Harrison power stations.
In addition, there are several initiatives to reduce GHG emissions at the state and international level. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.
FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). FirstEnergy’s ability to achieve its GHG reduction goal is subject to its ability to make operational changes and is conditioned upon numerous risks, many of which are outside of its control. With respect to FirstEnergy’s coal-fired plants in West Virginia, which serve as the primary source of its Scope 1 emissions, it has 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 FirstEnergy is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s financial condition, results of operations, and cash flow. 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.
FirstEnergy continues to monitor climate change policies at both the federal and state level. Currently, FirstEnergy anticipates continued uncertainty, and may need to make decisions even as policies shift from administration to administration.
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 were renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025, for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the U.S. Court of Appeals for the Fifth and Eighth Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the rule pending disposition on the merits. A number of other parties have challenged the final rule in various petitions for review across several circuits. Those petitions and motions for stay have been consolidated in the U.S. Court of Appeals for the Eighth Circuit Court. On October 10, 2024, the Eighth Circuit denied the motions for stay. On February 19, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.
On February 28, 2025, the D.C. Circuit granted EPA’s motion. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the 2024 ELG rule. Depending on the outcome of appeals and the EPA’s review, compliance with the 2024 ELG rule could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. During 2024, as a result of the evaluation of closure options for McElroy’s Run and the adjacent landfill, AE Supply reviewed its ARO and future expected costs to remediate, resulting in an increase to the ARO liability of $87 million. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025 with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. In connection with the transfer, AE Supply made a $15 million cash payment to the escrow account, recognized a $130 million liability, based on a 4.8% weighted average discount rate over the contract term, associated with its remaining obligation to fund the escrow account over the next five years, and derecognized the ARO, resulting in an immaterial impact to earnings.
On May 8, 2024, the EPA issued the Legacy CCR Rule, which finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. On February 13, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation, which was filed on August 8, 2024, by the Utility Solid Waste Act Group with FE as a member, in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed, which the D.C. Circuit granted. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the final Legacy CCR Rule. FirstEnergy continues to monitor the EPA’s actions related to CCR regulations; however, the ultimate impact is unknown at this time and is subject to the outcome of the litigation and any future state regulatory actions. Depending on the outcome of appeals and the EPA’s rule, compliance with the final Legacy CCR Rule could require remedial actions, including removal of coal ash. See Note 8, “Asset Retirement Obligations,” of the Combined Notes to Financial Statements of the Registrants above for a description of the $139 million increase to its ARO that FirstEnergy recorded during 2024 as a result of its analysis. JCP&L did not have any legacy CCR disposal sites that were applicable to the new CCR rule.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of March 31, 2025, 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 $98 million have been accrued through March 31, 2025, of which approximately $69 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
U.S. v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the U.S. Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District of Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. On January 17, 2025, the U.S. Attorney’s Office announced that a federal grand jury charged two former FirstEnergy senior officers with one count of participating in a Racketeer Influenced and Corrupt Organizations Act conspiracy. The allegations in the indictment are largely based on the conduct described in the DPA.
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 as to FE. Under the DPA, FE agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA required 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, consisting of (x) $115 million paid by FE to the U.S. Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 22, 2024, FirstEnergy had successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S. Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the aforementioned federal indictment against two former FirstEnergy senior officers. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information. On February 26, 2025, the U.S. Attorney’s Office filed a status report confirming these commitments.
Legal Proceedings Relating to U.S. v. Larry Householder, et al.
Certain FE stockholders and FirstEnergy customers also 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 alleged 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 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order; the Sixth Circuit granted FE’s petition on November 16, 2023, and heard oral argument on July 17, 2024. On November 30, 2023, FE filed a motion with the S.D. Ohio to stay all proceedings pending that circuit court appeal. Discovery was stayed during the pendency of that motion to stay all proceedings and on August 20, 2024, the S.D. Ohio denied FE’s motion and lifted the stay as to fact discovery. On July 29, 2024, FE filed in the U.S. Court of Appeals for the Sixth Circuit a Petition for Writ of Mandamus asking the Sixth Circuit to direct the district court to deny plaintiffs’ motion to compel disclosure of FE’s privileged internal investigation materials. On September 11, 2024, FE filed in the U.S. Court of Appeals for the Sixth Circuit a motion to stay discovery of the privileged internal investigation materials pending resolution of the Petition for Writ of Mandamus. 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 then-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. 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.
The outcome of any of these lawsuits 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 the Registrants’ normal business operations pending against them or their subsidiaries. The loss or range of loss in these matters is not expected to be material to the Registrants. The other potentially material items not otherwise discussed above are described under Note 9, “Regulatory Matters” of the Combined Notes to Financial Statements of the Registrants.
The Registrants accrue 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 the Registrants determine that it is not probable, but reasonably possible that they have a material obligation, they disclose such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that the Registrants 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 the Registrants’ financial condition, results of operations, and cash flows.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 1, "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants for a discussion of new accounting pronouncements.
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned subsidiary of FE. JCP&L conducts business in New Jersey by providing regulated electric transmission and distribution services in northern, western and east central New Jersey. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU. JCP&L is subject to regulation by the NJBPU and FERC.
JCP&L's reportable operating segments are comprised of the Distribution and Transmission segments.
The Distribution segment, representing $3.3 billion in rate base as of December 31, 2024, distributes electricity to approximately 1.2 million customers in New Jersey across its distribution footprint and procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.
The Transmission segment includes transmission infrastructure owned and operated by JCP&L and used to transmit electricity, representing $1.4 billion in rate base as of December 31, 2024. The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on JCP&L’s transmission facilities.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Executive Summary and Recent Developments, Regulatory Assets and Liabilities, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Pronouncements.
Summary of Results of Operations—First Quarter 2025 Compared with First Quarter 2024
Financial results for JCP&L's business segments for the three months ended March 31, 2025 and 2024, were as follows:
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| For the Three Months Ended March 31, 2025 |
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|
Reconciling |
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| (In millions) |
|
Distribution |
|
Transmission |
|
Adjustments |
|
JCP&L |
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|
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|
|
|
|
|
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| Revenues |
|
$ |
548 |
|
|
$ |
61 |
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|
$ |
(43) |
|
|
$ |
566 |
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|
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|
|
|
|
|
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| Operating Expenses: |
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|
|
|
|
|
|
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| Purchased power |
|
298 |
|
|
— |
|
|
— |
|
|
298 |
|
| Other operating expenses |
|
174 |
|
|
14 |
|
|
(43) |
|
|
145 |
|
| Provision for depreciation |
|
53 |
|
|
12 |
|
|
— |
|
|
65 |
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| Deferral of regulatory assets, net |
|
(22) |
|
|
— |
|
|
— |
|
|
(22) |
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| General taxes |
|
6 |
|
|
— |
|
|
— |
|
|
6 |
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| Total operating expenses |
|
509 |
|
|
26 |
|
|
(43) |
|
|
492 |
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| Other Income (Expense): |
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| Miscellaneous income, net |
|
12 |
|
|
— |
|
|
— |
|
|
12 |
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|
|
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|
|
|
|
|
|
| Interest expense - other |
|
(22) |
|
|
(7) |
|
|
— |
|
|
(29) |
|
| Interest expense - affiliates |
|
(1) |
|
|
— |
|
|
— |
|
|
(1) |
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| Capitalized financing costs |
|
3 |
|
|
6 |
|
|
— |
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|
9 |
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| Total other expense |
|
(8) |
|
|
(1) |
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— |
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|
(9) |
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|
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| Income taxes |
|
7 |
|
|
9 |
|
|
— |
|
|
16 |
|
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|
|
| Net Income |
|
$ |
24 |
|
|
$ |
25 |
|
|
$ |
— |
|
|
$ |
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, 2024 |
|
|
|
|
|
Reconciling |
|
|
| (In millions) |
|
Distribution |
|
Transmission |
|
Adjustments |
|
JCP&L |
|
|
|
|
|
|
|
|
|
| Revenues: |
|
$ |
452 |
|
|
$ |
52 |
|
|
$ |
(38) |
|
|
$ |
466 |
|
|
|
|
|
|
|
|
|
|
| Operating Expenses: |
|
|
|
|
|
|
|
|
| Purchased power |
|
248 |
|
|
— |
|
|
— |
|
|
248 |
|
| Other operating expenses |
|
211 |
|
|
14 |
|
|
(38) |
|
|
187 |
|
| Provision for depreciation |
|
50 |
|
|
11 |
|
|
— |
|
|
61 |
|
| Deferral of regulatory assets, net |
|
(39) |
|
|
— |
|
|
— |
|
|
(39) |
|
| General taxes |
|
5 |
|
|
— |
|
|
— |
|
|
5 |
|
| Total operating expenses |
|
475 |
|
|
25 |
|
|
(38) |
|
|
462 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other Income (Expense): |
|
|
|
|
|
|
|
|
| Miscellaneous income, net |
|
11 |
|
|
— |
|
|
— |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
| Interest expense - other |
|
(23) |
|
|
(7) |
|
|
— |
|
|
(30) |
|
| Interest expense - affiliates |
|
(4) |
|
|
— |
|
|
— |
|
|
(4) |
|
| Capitalized financing costs |
|
2 |
|
|
5 |
|
|
— |
|
|
7 |
|
| Total other income (expense) |
|
(14) |
|
|
(2) |
|
|
— |
|
|
(16) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income taxes (benefits) |
|
(11) |
|
|
7 |
|
|
— |
|
|
(4) |
|
|
|
|
|
|
|
|
|
|
| Net Income (loss) |
|
$ |
(26) |
|
|
$ |
18 |
|
|
$ |
— |
|
|
$ |
(8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes Between Three Months Ended
March 31, 2025 and 2024 Financial Results
|
|
|
|
|
|
Reconciling |
|
|
| (In millions) |
|
Distribution |
|
Transmission |
|
Adjustments |
|
JCP&L |
|
|
|
|
|
|
|
|
|
| Revenues |
|
$ |
96 |
|
|
$ |
9 |
|
|
$ |
(5) |
|
|
$ |
100 |
|
|
|
|
|
|
|
|
|
|
| Operating Expenses: |
|
|
|
|
|
|
|
|
| Purchased power |
|
50 |
|
|
— |
|
|
— |
|
|
50 |
|
| Other operating expenses |
|
(37) |
|
|
— |
|
|
(5) |
|
|
(42) |
|
| Provision for depreciation |
|
3 |
|
|
1 |
|
|
— |
|
|
4 |
|
| Deferral of regulatory assets, net |
|
17 |
|
|
— |
|
|
— |
|
|
17 |
|
| General taxes |
|
1 |
|
|
— |
|
|
— |
|
|
1 |
|
| Total operating expenses |
|
34 |
|
|
1 |
|
|
(5) |
|
|
30 |
|
|
|
|
|
|
|
|
|
|
| OPERATING INCOME |
|
62 |
|
|
8 |
|
|
— |
|
|
70 |
|
|
|
|
|
|
|
|
|
|
| Other Income (Expense): |
|
|
|
|
|
|
|
|
| Miscellaneous income, net |
|
1 |
|
|
— |
|
|
— |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
| Interest expense - other |
|
1 |
|
|
— |
|
|
— |
|
|
1 |
|
| Interest expense - affiliates |
|
3 |
|
|
— |
|
|
— |
|
|
3 |
|
| Capitalized financing costs |
|
1 |
|
|
1 |
|
|
— |
|
|
2 |
|
| Total other income (expense) |
|
6 |
|
|
1 |
|
|
— |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income taxes (benefits) |
|
18 |
|
|
2 |
|
|
— |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
| Net Income (Loss) |
|
$ |
50 |
|
|
$ |
7 |
|
|
$ |
— |
|
|
$ |
57 |
|
Distribution - Results of Operations
Net income increased $50 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to higher revenues from the implementation of the base rate case in February 2024, the absence of a $53 million charge in connection with the base rate case settlement agreement, as further discussed below, higher customer usage and demand, and regulated investment programs, partially offset by higher operating expenses.
Revenues
The $96 million increase in total revenues resulted from the following sources:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, |
| Revenues by Type of Service |
1 |
2025 |
|
2024 |
|
Increase / (Decrease) |
|
|
(In millions) |
| Distribution services |
|
$ |
266 |
|
|
$ |
216 |
|
|
$ |
50 |
|
|
|
|
|
|
|
|
| Generation sales: |
|
|
|
|
|
|
| Retail |
|
277 |
|
|
228 |
|
|
49 |
|
| Wholesale |
|
1 |
|
|
2 |
|
|
(1) |
|
| Total generation sales |
|
278 |
|
|
230 |
|
|
48 |
|
|
|
|
|
|
|
|
| Other |
|
4 |
|
|
6 |
|
|
(2) |
|
| Total Revenues |
|
$ |
548 |
|
|
$ |
452 |
|
|
$ |
96 |
|
Distribution services revenue increased $50 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher revenues from the implementation of the base rate case in February 2024, higher customer usage as a result of colder weather temperatures, higher weather-adjusted customer usage and demand, and higher rider revenues associated with certain regulated investment programs.
Generation sales revenues increased $48 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher retail sales volumes and non-shopping generation auction rates. Retail generation sales have no material impact to earnings.
Operating Expenses
Total operating expenses increased by $34 million primarily due to:
◦Purchased power costs, which have no material impact to earnings, increased by $50 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher unit costs and sales volumes.
◦Other operating expenses decreased $37 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to:
▪The absence of a $53 million pre-tax charge at JCP&L in the first quarter 2024 associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the base rate case settlement agreement, to be disallowed from future recovery; and
▪Lower storm restoration expenses of $5 million, which were deferred for future recovery.
The decrease was partially offset by:
▪Higher severance and related costs of $4 million associated with FirstEnergy’s organizational changes announced in the first quarter of 2025;
▪Higher uncollectible expenses of $4 million, which were deferred for future recovery; and
▪Higher energy efficiency and other state mandated program costs of $13 million, which were deferred for future recovery, resulting in no material impact to earnings.
◦Depreciation expense increased $3 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to a higher asset base.
◦Deferral of regulatory assets, net decreased $17 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to a $5 million decrease from lower deferral of storm related expenses, a $3 million net decrease from lower generation and transmission related deferrals, and $9 million related to net decreases in other deferrals.
Other Expenses
Total other expenses decreased $6 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to lower interest on short-term borrowings and higher capitalized interest.
Income Taxes
The distribution segment's effective tax rate for the three months ended March 31, 2025 and 2024, was 22.6% and 29.7%, respectively. The decrease in the effective tax rate is primarily due to an increase in the tax benefit from AFUDC equity flow-through.
Transmission - Results of Operations
Net income increased $7 million in the first quarter of 2025, as compared to the same period of 2024, primarily due to higher revenues from regulated investment programs as further discussed below.
Revenues
Transmission revenue increased $9 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to a higher rate base from regulated investments and recovery of higher transmission operating expenses.
Operating Expenses
Total operating expenses increased by $1 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher depreciation expenses from a higher asset base. Nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expenses
Total other expenses decreased by $1 million during the first quarter of 2025, as compared to the same period of 2024, primarily due to higher capitalized financing costs.
Income Taxes
The transmission segment's effective tax rate for the three months ended March 31, 2025 and 2024, was 26.5% and 28.0%, respectively. The decrease in the effective tax rate is primarily due to an increase in the tax benefit from AFUDC equity flow-through.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
The management of the Registrants, with the participation of their respective principal executive officer and principal financial officer, have established and evaluated the effectiveness of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the principal executive officers and principal financial officers of the Registrants have concluded that the disclosure controls and procedures in place were effective as of the end of the period covered by this report.
(b) Changes in Internal Control over Financial Reporting
During the quarter ended March 31, 2025, 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, the Registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Note 9, “Regulatory Matters,” and Note 10, “Commitments, Guarantees and Contingencies,” of the Combined Notes to Financial Statements of the Registrants in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
You should carefully consider the FirstEnergy risk factors discussed in "Item 1A. Risk Factors" in FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 27, 2025.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION.
Trading Arrangements
During the quarter ended March 31, 2025, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of the Registrants adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408 of Regulation S-K).
ITEM 6. EXHIBITS
|
|
|
|
|
|
|
|
|
|
|
|
| Exhibit Number |
Description |
|
|
|
|
| FirstEnergy |
| (A)(B) |
10.1 |
|
|
| (A)(B) |
10.2 |
|
|
| (A) |
31.1 |
|
|
| (A) |
31.2 |
|
|
| (A) |
32 |
|
|
|
101 |
|
The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2025, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows, (v) related notes to these financial statements and (vii) document and entity information. |
|
104 |
|
Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document contained in Exhibit 101) |
|
|
|
|
| JCP&L |
| (A) |
31.1 |
|
|
| (A) |
31.2 |
|
|
| (A) |
32 |
|
|
|
101 |
|
The following materials from the Quarterly Report on Form 10-Q of Jersey Central Power & Light Company for the period ended , formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Statements of Income and Comprehensive Income, (ii) Balance Sheets, (iii) Statements of Stockholders Equity, (iv) Statements of Cash Flows, (v) related notes to these financial statements and (vi) document and entity information. |
|
104 |
|
Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document contained in Exhibit 101) |
|
|
|
|
|
|
|
|
(A) Provided herein in electronic format as an exhibit.
(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 and JCP&L have not filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets, but hereby agree to furnish to the SEC on request any such documents.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
April 30, 2025
|
|
|
|
|
|
|
FIRSTENERGY CORP. |
|
Registrant |
|
|
|
/s/ Jason J. Lisowski |
|
Jason J. Lisowski |
|
Vice President, Controller and Chief Accounting Officer |
|
(Principal Accounting Officer) |
|
|
|
|
|
JERSEY CENTRAL POWER & LIGHT COMPANY |
|
Registrant |
|
|
|
/s/ Tracy M. Ashton |
|
Tracy M. Ashton |
|
Controller |
|
(Principal Accounting Officer) |
EX-10.1
2
feq12025-ex101.htm
EX-10.1
Document
Exhibit 10.1
(Stock-Based Agreement)
FIRSTENERGY CORP.
2020 Incentive Compensation Plan
2025-2027 Performance-Adjusted Restricted Stock Unit Award Agreement
THIS 2025-2027 PERFORMANCE-ADJUSTED RESTRICTED STOCK UNIT AWARD AGREEMENT (the “Agreement”), effective as of #GrantDate#, (the “Grant Date”), is entered into by and between the Company and #ParticipantName# (the “Grantee”) in accordance with the terms of the FirstEnergy Corp. 2020 Incentive Compensation Plan (the “Plan”).
1. Definitions. Unless otherwise specified in this Agreement, capitalized terms shall have the meanings attributed to them under the Plan. For purposes of this Agreement, “Retirement” shall mean the Grantee’s termination of employment (except due to death or by the Company for Cause) on or after attaining age 55 and after providing at least five years of service to the Company or any Subsidiary or affiliate or any predecessor thereof.
2. Grant of Restricted Stock Units. As of the Grant Date, the Company has granted to the Grantee #QuantityGranted# (the “Target Number”) Restricted Stock Units (the “Restricted Stock Units” or “RSUs”), a percentage of which Target Number will vest and become payable in accordance with the terms and conditions of this Agreement. The Target Number shall be adjusted with respect to Dividend Equivalents as provided in Section 8 below. Each RSU that becomes vested and payable hereunder represents the right of the Grantee to receive one Share subject to the terms and conditions of this Agreement. The RSUs are granted in accordance with, and subject to, all the terms, conditions and restrictions of the Plan, which is hereby incorporated by reference in its entirety. The Grantee irrevocably agrees to, and accepts, the terms, conditions and restrictions of the Plan and this Agreement on the Grantee’s own behalf and on behalf of any heirs, successors and assigns.
3. Restrictions on RSUs. Except as otherwise provided herein, the Grantee cannot sell, transfer, assign, hypothecate or otherwise dispose of the RSUs or pledge any RSU as collateral for a loan, other than by will or by the laws of descent and distribution. In no event may any RSU or this Award be transferred for value. In addition, the RSUs, and any payments made with respect to the RSUs, will be subject to such other restrictions as the Committee deems necessary or appropriate, including, without limitation, the Company’s Second Amended and Restated Executive Compensation Recoupment Policy and the Compensation Clawback Policy, each as may be amended (or succeeded) from time to time, to the extent applicable.
4. Vesting and Settlement of RSUs.
(a) Vesting. Except as otherwise provided in Sections 6 and 7 below, if and to the extent the performance goals set forth on Exhibit A attached to this Agreement (the “Performance Goals”) are achieved during the performance period set forth on Exhibit A (the “Performance Period”), a percentage of the Target Number of RSUs will vest on March 1, 2028 (the “Vesting Date”), as long as the Grantee remains continuously employed by the Company or a Subsidiary until such Vesting Date. The number of RSUs that shall vest will range from 0% to 200% of the Target Number, based on the extent to which the Performance Goals are achieved, as determined by the Committee in its sole discretion. The Grantee will have no rights to the Shares underlying the RSUs until the RSUs have vested and been settled (each RSU that vests pursuant to this Section 4 or Sections 6 and 7 below, a “Vested RSU”). Prior to settlement, each RSU (whether or not a Vested RSU) represents an unfunded and unsecured obligation of the Company.
(b) No Fractional Shares. If the number of shares on the Vesting Date would produce fractional RSUs, the number of RSUs that vest shall be rounded up to the nearest whole RSU.
(c) Settlement. Except as otherwise provided in Sections 6, 7 and 11 below, the Company shall settle each Vested RSU by delivering one Share per Vested RSU to the Grantee as soon as administratively practicable (and no later than 60 days) after the Vesting Date. Notwithstanding the foregoing or any provision in Sections 6 or 7 to the contrary, if the Grantee elects to defer the settlement of the RSUs pursuant to the Company’s Executive Deferred Compensation Plan (or any other non-qualified deferred compensation plan providing for the ability to defer settlement of the RSUs), then the time, form and medium of payment with respect to any deferred RSUs shall be made pursuant to the terms and conditions of the Executive Deferred Compensation Plan (or similar non-qualified deferred compensation plan, as applicable).
5. Forfeiture. Except as otherwise provided in Sections 6 and 7, the Grantee will forfeit the Grantee’s interest in the RSUs to the extent the Performance Goals are not achieved during the Performance Period, as determined by the Committee in its sole discretion, or if the Grantee terminates the Grantee’s employment with the Company and its Subsidiaries prior to the Vesting Date.
6. Certain Events. Notwithstanding any provision in this Agreement to the contrary and in each case subject to Section 6(g) below:
(a) Death. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee dies, a prorated number of RSUs shall become Vested RSUs. For purposes of this Section 6(a), the number of RSUs that shall become Vested RSUs due to the Grantee’s death shall be equal to (i) the Target Number of RSUs multiplied by (ii) a fraction (not greater than one), where the numerator is the number of full calendar months the Grantee remained employed after the Grant Date and the denominator is 36. The Company shall settle any RSUs that become Vested RSUs under this Section 6(a) by delivering to the Grantee’s estate one Share for each Vested RSU as soon as administratively practicable after the date of the Grantee’s death, but in any event by March 15th of the calendar year following the calendar year in which the Grantee’s death occurred in order to qualify as exempt from Section 409A of the Code under Treasury Regulation § 1.409A-1(b)(4).
(b) Disability. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee’s employment is terminated due to the Grantee’s Disability, then, after the end of the Performance Period, a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below). The Company shall settle any RSUs that become Vested RSUs under this Section 6(b) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Vesting Date, but in any event by March 15th of the calendar year following the calendar year in which the Performance Period ends in order to qualify as exempt from Section 409A of the Code under Treasury Regulation § 1.409A-1(b)(4).
(c) Termination without Cause. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee’s employment is terminated by the Company and its Subsidiaries without Cause, then, after the end of the Performance Period, a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below). The Company shall settle any RSUs that become Vested RSUs under this Section 6(c) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Vesting Date, but in any event by March 15th of the calendar year following the calendar year in which the Performance Period ends in order to qualify as exempt from Section 409A of the Code under Treasury Regulation § 1.409A-1(b)(4).
(d) Retirement. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee’s employment is terminated due to the Grantee’s Retirement, then, after the end of the Performance Period, a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below). The Company shall settle any RSUs that become Vested RSUs under this Section 6(d) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Vesting Date, but in any event by March 15th of the calendar year following the calendar year in which the Performance Period ends in order to qualify as exempt from Section 409A of the Code under Treasury Regulation § 1.409A-1(b)(4).
(e) Change in Position. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee is transferred to a position with the Company or a Subsidiary that is not an executive position eligible for an award such as this Award, then, after the end of the Performance Period, a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below). The Company shall settle any RSUs that become Vested RSUs under this Section 6(e) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Vesting Date, but in any event by March 15th of the calendar year following the calendar year in which the Performance Period ends in order to qualify as exempt from Section 409A of the Code under Treasury Regulation § 1.409A-1(b)(4).
(f) Prorated Vesting. The Prorated Number of RSUs described in Section 6(b), (c), (d) or (e) above (the “Prorated Number”) shall be determined as follows:
The Prorated Number = X multiplied by (Y/Z), where
X = the number of RSUs that would have become Vested RSUs based on actual performance against the Performance Goals if the Grantee had remained employed (and in an eligible executive position) until the Vesting Date;
Y = the number of full calendar months the Grantee remained employed (and in an eligible executive position) after the Grant Date; and
Z = 36.
(g) Release Requirement. Notwithstanding any provision herein to the contrary, except as otherwise determined by the Company, in order for the Grantee to receive Shares
pursuant to the settlement of Vested RSUs under Section 6(a), (b), (c), (d) or (e) above, the Grantee (or the representative of the Grantee’s estate) must execute and deliver to the Company a general release and waiver of claims against the Company, its Subsidiaries and their directors, officers, employees, shareholders and other affiliates in a form that is satisfactory to the Company (the “Release”). The Release must become effective and irrevocable under applicable law no later than 60 days following the date of the Grantee’s death, termination of employment or transfer of position, as applicable.
7. Change in Control. If a Change in Control occurs, the RSUs shall generally become subject to the terms and conditions of Article 16 of the Plan; provided that if the RSUs subject to this Agreement are not replaced with a Replacement Award, then a prorated number of the RSUs (as determined by the formula in the following sentence) shall become Vested RSUs as of the date of the Change in Control and shall be settled no later than 60 days after the Change in Control in the manner set forth in Article 16 of the Plan. For purposes of this Section 7, the prorated number of RSUs that may become Vested RSUs upon a Change in Control shall be equal to the Target Number of RSUs granted hereunder times a fraction (not greater than one), in which the numerator is the number of full months completed from the Grant Date to the date of the consummation of the Change in Control and the denominator is 36.
8. Dividend Equivalents. Until the date on which the RSUs are settled for Shares (or cash in the case of RSUs deferred under the Company’s Executive Deferred Compensation Plan), and pursuant to the terms and conditions of this Agreement, the Grantee will be credited (in the manner described in the following sentences) on the books and records of the Company with an amount per each RSU equal to the amount per share of any cash dividends declared by the Board of Directors of the Company with a record date on or after the Grant Date on the outstanding Shares (such amount, a “Dividend Equivalent”). Such Dividend Equivalents will be credited in the form of an additional number of RSUs and the Target Number of RSUs shall be adjusted by each additional RSU credited to the Grantee pursuant to the Dividend Equivalents. The additional number of RSUs will be equal to the aggregate amount of Dividend Equivalents credited under this Agreement on the respective dividend payment date divided by the average of the high and low prices per Share on the respective dividend payment date. The RSUs attributable to the Dividend Equivalents will be either settled or forfeited, as appropriate, under the same terms and conditions that apply to the other RSUs under this Award Agreement, including the achievement of the Performance Goals and any action taken by the Committee. For the avoidance of doubt, if the Grantee defers settlement of any portion of the RSUs pursuant to the Executive Deferred Compensation Plan, then, during the deferral period, the Grantee’s stock account under the Executive Deferred Compensation Plan shall continue to be credited with Dividend Equivalents pursuant to this Section 8 until such deferred RSUs are settled for Shares or cash, as applicable, under the terms of the Executive Deferred Compensation Plan.
9. Continuous Employment. So long as the Grantee continues to be an employee of the Company or any of its Subsidiaries, the Grantee shall not be considered to have experienced a termination of employment because of: (a) any temporary leave of absence approved in writing
by the Company or such Subsidiary; or (b) any change of duties or position (including transfer from one Subsidiary to another); provided, however, that, in the case of any change of duties or position that results in the Grantee no longer being an executive of the Company or a Subsidiary, the terms of Section 6(e) shall apply.
10. Delivery of Shares. Upon settlement of any RSUs under this Agreement, the Company will deliver to the Grantee (or the Grantee’s estate) the Shares to which the Grantee is entitled free and clear of any restrictions (except any restrictions under applicable securities laws or otherwise imposed under the Plan or Section 3 hereof).
11. Withholding. Upon settlement of the RSUs, the Company shall withhold a number of Shares (or amount of cash, if applicable) in an amount sufficient to satisfy all federal, state, and local taxes to be withheld in connection with the settlement of RSUs under this Agreement.
12. No Shareholder Rights. The Grantee shall have no shareholder rights (or rights as a beneficial owner), including no voting rights, with respect to any RSU or the Share underlying the RSU unless and until the Grantee receives the Share upon settlement of the RSU.
13. Recoupment. If the Grantee is or has been deemed to be, or becomes, an “officer” for purposes of Section 16 of the Exchange Act, this Agreement will be administered in compliance with Section 10D of the Exchange Act, any applicable rules or regulations promulgated by the Securities and Exchange Commission or any national securities exchange or national securities association on which the Shares may be traded, and subject to the Company’s Executive Compensation Recoupment and Clawback Policies, as amended (or succeeded) from time to time, or any other Company policy adopted pursuant to such law, rules, or regulations and this Agreement may be amended to further such purpose without the consent of the Grantee.
14. Termination of Agreement. This Agreement will terminate on the earliest of: (a) the date of the Grantee’s termination of employment with the Company, except if such termination of employment is due to death, Disability, Retirement, or a termination by the Company without Cause; (b) the date the RSUs are settled pursuant to the terms of this Agreement; or (c) if no RSUs have become Vested RSUs as of the Vesting Date, the Vesting Date. Any terms or conditions of this Agreement that the Company determines are reasonably necessary to effectuate its purposes shall survive the termination of this Agreement.
15. Miscellaneous Provisions.
(a) Adjustments. In the event of a corporate event or transaction described in Section 4.5 of the Plan, this Award and the RSUs granted hereunder shall be subject to mandatory adjustment as described in Section 4.5 of the Plan.
(b) Successors and Legal Representatives. This Agreement will bind and inure to the benefit of the Company and the Grantee, and their respective successors, assigns and legal representatives.
(c) Integration. This Agreement, together with the Plan, constitutes the entire agreement between the Grantee and the Company with respect to the subject matter hereof. Any waiver of any term, condition or breach thereof will not be a waiver of any other term or condition or of the same term or condition for the future, or of any subsequent breach. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern, except with respect to the Committee’s authority to adjust downward the number of RSUs that vest under this Agreement, as provided under Section 15(h) below.
(d) Notice. Any notice relating to this grant must be in writing, which may include an electronic writing.
(e) No Employment Right Created. Nothing in this Agreement will be construed to confer upon the Grantee the right to continue in the employment or service of the Company or any of its Subsidiaries, or to be employed or serve in any particular position therewith or affect any right which the Company or any of its Subsidiaries may have to terminate the Grantee’s employment or service with or without cause.
(f) Severability. In the event of the invalidity of any part or provision of this Agreement, such invalidity will not affect the enforceability of any other part or provision of this Agreement.
(g) Section Headings. The section headings of this Agreement are for convenience of reference only and are not intended to define, extend or limit the contents of the sections.
(h) Amendment. The terms and conditions of this Agreement may be modified by the Committee:
(i) in any case permitted by the terms of the Plan or this Agreement;
(ii) except with respect to an adjustment made pursuant to the last paragraph of this Section 15(h), with the written consent of the Grantee; or
(iii) without the consent of the Grantee if the amendment is either not materially adverse to the interests of the Grantee or is necessary or appropriate in the view of the Committee to conform with, or to take into account, applicable law, including either exemption from or compliance with any applicable tax law.
Notwithstanding any provision in this Agreement or the Plan to the contrary, the Committee shall retain the discretion to adjust the number of RSUs that vest under this Agreement without the Grantee’s consent, notwithstanding the Company’s actual performance against the Performance Goals, either on a formula or discretionary basis or a combination of the two, as the Committee determines in its sole discretion.
(i) Plan Administration. The Plan is administered by the Committee, which has full and exclusive discretionary power to interpret, implement, construe and adopt rules, forms and guidelines for administering the Plan and this Agreement. All actions, interpretations and determinations made by the Committee, the Board of Directors, or any of their delegates as to the provisions of this Agreement and the Plan shall be final, conclusive, and binding on all persons and the Grantee agrees to be bound by such actions, interpretations and determinations.
(j) Governing Law. Except as may otherwise be provided in the Plan, this Agreement will be governed by, construed and enforced in accordance with the internal laws of the State of Ohio, without giving effect to its principles of conflict of laws. By accepting this Award, the Grantee agrees to the exclusive jurisdiction and venue of the courts of the United States District Court for the Northern District of Ohio or the Summit County (Ohio) Court of Common Pleas to adjudicate any and all claims brought with respect to this Agreement.
(k) Internal Revenue Code Section 409A. Notwithstanding anything in the Plan or this Agreement to the contrary, the Award of RSUs granted hereunder is intended to meet any applicable requirements for compliance under, or exemption from (specifically, the short-term deferral exception under Treasury Regulation § 1.409A-1(b)(4)), Code Section 409A and this Agreement shall be construed and administered accordingly. However, notwithstanding anything in this Agreement to the contrary, the Company makes no representations or warranties as to the tax effects of payments made to the Grantee (or the Grantee’s estate) pursuant to this Agreement, and any and all tax consequences incident to such shall solely be the responsibility of the Grantee (or the Grantee’s estate).
(l) Data Privacy. In order to implement, administer and manage the Grantee’s participation in the Plan, the Company and its affiliates may hold certain personal information about the Grantee, including, but not limited to, the Grantee’s name, home address and telephone number, date of birth, social security number or other identification number, salary, nationality, job title, any Shares or directorships held in the Company or any affiliate, details of all Awards or any other entitlement to Shares awarded, canceled, exercised, vested, unvested or outstanding in the Grantee’s favor, for the exclusive purpose of implementing, administering and managing the Plan (collectively, the “Personal Data”).
The Grantee hereby explicitly and unambiguously consents to the collection, use and transfer, in electronic or other form, of the Grantee’s Personal Data as described above, as applicable, to the Company and its affiliates for the sole purpose of administering the Plan. The Grantee understands that Personal Data may be transferred to third parties assisting in the implementation, administration and management of the Plan, that these recipients may be located in the United States or elsewhere, and that the recipient’s country may have different data privacy laws and protections than the United States or the Grantee’s state of residence. The Grantee understands that the Grantee may request a list with the names and addresses of any potential recipients of the Personal Data by contacting the Executive Compensation group of Human Resources. The Grantee authorizes the recipients to receive, possess, use, retain and transfer the Personal Data, in electronic or other form, for the purposes of implementing,
administering and managing the Grantee’s participation in the Plan, including any requisite transfer of such Personal Data as may be required to a broker or other third party with whom the Grantee may elect to deposit any Shares received upon vesting of the RSUs. The Grantee understands that Personal Data will be held only as long as is necessary to implement, administer and manage the Grantee’s participation in the Plan and to comply with Securities and Exchange Commission and/or NYSE reporting obligations, any other applicable law or regulation and any applicable document retention policies of the Company. The Grantee understands that the Grantee may, at any time, view Personal Data, request additional information about the storage and processing of Personal Data, require any necessary amendments to Personal Data or refuse or withdraw the consents herein, without cost, by contacting in writing the Executive Compensation group of Human Resources. The Grantee understands that refusal or withdrawal of consent may affect the Grantee’s ability to participate in the Plan or to realize benefits from the RSUs. For more information on the consequences of the Grantee’s refusal to consent or withdrawal of consent, the Grantee understands that the Grantee may contact the Executive Compensation group of Human Resources.
(m) Signatures and Electronic Delivery. This Agreement may be executed electronically and in counterparts, each of which shall be deemed to be an original, and when taken together shall constitute one binding agreement. The Company may, in its sole discretion, deliver any documents related to current or future participation in the Plan by electronic means. The Grantee hereby consents to receive such documents by electronic delivery and agrees to participate in the Plan through an on-line or electronic system established and maintained by the Company or another third party designated by the Company.
[SIGNATURE ON FOLLOWING PAGE]
The Grantee acknowledges receipt of this Agreement and accepts and agrees with the terms and conditions stated above.
#AcceptanceDate# ____#Signature#______
(Date) (Signature of the Grantee)
EXHIBIT A
Performance Goals
Performance Period
The Performance Period for this Agreement is January 1, 2025 through December 31, 2027.
Performance Goals1
The Performance Goals, as approved by the Committee, for the Performance Period are based on:
1 Notwithstanding any other provision of this Agreement, in addition to any other rights of the Committee under the Plan (as defined in the Agreement), the Committee may, in any evaluation of the Company’s level of achievement with respect to the Performance Goals, include or exclude any of the following events that occur during the Performance Period: (a) asset write-downs; (b) litigation or claim judgments or settlements; (c) the effect of changes in tax laws, accounting principles or other laws or provisions affecting reported results; (d) any reorganization and restructuring programs; (e) extraordinary nonrecurring items; (f) acquisitions or divestitures and/or (g) foreign exchange gains and losses.
EX-10.2
3
feq12025-ex102.htm
EX-10.2
Document
FIRSTENERGY CORP.
2020 Incentive Compensation Plan
2025 Time-Based Restricted Stock Unit Award Agreement
THIS 2025 TIME-BASED RESTRICTED STOCK UNIT AWARD AGREEMENT (the “Agreement”), effective as of #GrantDate#, (the “Grant Date”), is entered into by and between FirstEnergy Corp. (the “Company”) and #ParticipantName# (the “Grantee”) in accordance with the terms of the FirstEnergy Corp. 2020 Incentive Compensation Plan (the “Plan”).
1. Definitions. Unless otherwise specified in this Agreement, capitalized terms shall have the meanings attributed to them under the Plan. For purposes of this Agreement, “Retirement” shall mean the Grantee’s termination of employment (except due to death or by the Company for Cause) on or after attaining age 55 and after providing at least five years of service to the Company or any Subsidiary or affiliate or any predecessor thereof.
2. Grant of Restricted Stock Units. As of the Grant Date, the Company has granted to the Grantee #QuantityGranted# (the “Target Number”) Restricted Stock Units (the “RSUs”), a percentage of which Target Number will vest and become payable in accordance with the terms and conditions of this Agreement. The Target Number shall be adjusted with respect to Dividend Equivalents as provided in Section 8 below. Each RSU that becomes vested and payable hereunder represents the right of the Grantee to receive one Share subject to the terms and conditions of this Agreement. The RSUs are granted in accordance with, and subject to, all the terms, conditions and restrictions of the Plan, which is hereby incorporated by reference in its entirety. The Grantee irrevocably agrees to, and accepts, the terms, conditions and restrictions of the Plan and this Agreement on the Grantee’s own behalf and on behalf of any heirs, successors and assigns.
3. Restrictions on RSUs. Except as otherwise provided herein, the Grantee cannot sell, transfer, assign, hypothecate or otherwise dispose of the RSUs or pledge any RSU as collateral for a loan, other than by will or by the laws of descent and distribution. In no event may any RSU or this Award be transferred for value. In addition, the RSUs, and any payments made with respect to the RSUs, will be subject to such other restrictions as the Committee deems necessary or appropriate, including, without limitation, the Company’s Second Amended and Restated Executive Compensation Recoupment Policy and the Compensation Clawback Policy, each as may be amended (or succeeded) from time to time, to the extent applicable.
4. Vesting and Settlement of RSUs.
(a) Vesting. Except as otherwise provided in Sections 6 and 7 below, the RSUs shall become vested on March 1, 2028 (the “Vesting Date”), provided that the Participant continues to be employed by the Company from the Grant Date until the Vesting Date.
(b) No Fractional Shares. If any prorated vesting in accordance with Section 6 or 7 or the crediting of Dividend Equivalents in accordance with Section 8 would produce fractional RSUs, the number of RSUs that vest shall be rounded up to the nearest whole RSU.
(c) Rights Prior to Vesting. The Grantee will have no rights to the Shares underlying the RSUs until the RSUs have vested and been settled (each RSU that vests pursuant to this Section 4 or Sections 6 and 7 below, a “Vested RSU”). Prior to settlement, each RSU (whether or not a Vested RSU) represents an unfunded and unsecured obligation of the Company.
(d) Settlement. Except as otherwise provided in Sections 6, 7 and 11 below, the Company shall settle each Vested RSU by delivering one Share per Vested RSU to the Grantee as soon as administratively practicable (and no later than 60 days) after the Vesting Date. Notwithstanding the foregoing or any provision in Sections 6 or 7 to the contrary, if the Grantee elects to defer the settlement of the RSUs pursuant to the Company’s Executive Deferred Compensation Plan (or any other non-qualified deferred compensation plan providing for the ability to defer settlement of the RSUs), then the time, form and medium of payment with respect to any deferred RSUs shall be made pursuant to the terms and conditions of the Executive Deferred Compensation Plan (or similar non-qualified deferred compensation plan, as applicable).
5. Forfeiture. Except as otherwise provided in Sections 6 and 7, the Grantee will forfeit the Grantee’s interest in the RSUs if the Grantee terminates the Grantee’s employment with the Company or any Subsidiary prior to the Vesting Date.
6. Certain Events. Notwithstanding any provision in this Agreement to the contrary and in each case subject to Section 6(g) below:
(a) Death. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee dies, then a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below) upon the Grantee’s death. The Company shall settle any RSUs that become Vested RSUs under this Section 6(a) by delivering to the Grantee’s estate one Share for each Vested RSU as soon as administratively
practicable after the date of the Grantee’s death, but in any event within 60 days following the Grantee’s death.
(b) Disability. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee’s employment is terminated due to the Grantee’s Disability, then a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below) upon such termination date. The Company shall settle any RSUs that become Vested RSUs under this Section 6(b) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Grantee’s termination of employment, but in any event within 60 days following the Grantee’s termination of employment.
(c) Termination without Cause. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee’s employment is terminated by the Company and its Subsidiaries without Cause, then a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below) upon such termination date. Except as otherwise provided in Section 15(k), the Company shall settle any RSUs that become Vested RSUs under this Section 6(c) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Grantee’s termination of employment, but in any event within 60 days following the Grantee’s termination of employment.
(d) Retirement. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee’s employment is terminated due to the Grantee’s Retirement, then a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below) upon such termination date. Except as otherwise provided in Section 15(k), the Company shall settle any RSUs that become Vested RSUs under this Section 6(d) by delivering to the Grantee one Share for each Vested RSU as soon as administratively practicable after the Grantee’s termination of employment, but in any event within 60 days following the Grantee’s termination of employment.
(e) Change in Position. If, at least one month after the Grant Date but prior to the Vesting Date, the Grantee is transferred to a position with the Company or a Subsidiary that is not eligible for an award such as this Award, then a Prorated Number of RSUs shall become Vested RSUs (as determined in Section 6(f) below) upon such change in position. The Company shall settle any RSUs that become Vested RSUs under this Section 6(e) by delivering to the Grantee one Share for each Vested RSU following the change in position on the earlier of the Grantee’s termination of employment (other than by the Company for Cause) or the Vesting Date.
(f) Prorated Vesting. The Prorated Number of RSUs described in Section 6(a), (b), (c), (d) or (e) above (the “Prorated Number”) shall be determined as follows:
The Prorated Number = X multiplied by (Y/Z), where
X = Target Number of RSUs;
Y = the number of full calendar months the Grantee remained employed (and in an eligible executive position) after the Grant Date; and
Z = 36.
(g) Release Requirement. Notwithstanding any provision herein to the contrary, except as otherwise determined by the Company, in order for the Grantee to receive Shares pursuant to the settlement of Vested RSUs under Section 6(a), (b), (c), (d) or (e) above, the Grantee (or the representative of the Grantee’s estate) must execute and deliver to the Company a general release and waiver of claims against the Company, its Subsidiaries and their directors, officers, employees, shareholders and other affiliates in a form that is satisfactory to the Company (the “Release”). The Release must become effective and irrevocable under applicable law no later than 60 days following the date of the Grantee’s death, termination of employment or transfer of position, as applicable.
7. Change in Control. If a Change in Control occurs, the RSUs shall generally become subject to the terms and conditions of Article 16 of the Plan; provided that if the RSUs subject to this Agreement are not replaced with a Replacement Award, then a prorated number of the RSUs (as determined by the formula in the following sentence) shall become Vested RSUs as of the date of the Change in Control and shall be settled no later than 60 days after the Change in Control in the manner set forth in Article 16 of the Plan; provided that the Change in Control is a “change in control event” as set forth in Treas. Reg. 1.409A-3(i)(5). If the Change in Control is not a “change in control event” as set forth in Treas. Reg. 1-409A(i)(5), then the Vested RSUs shall be settled upon the earlier of the Grantee’s termination of employment upon or following the Change in Control or the Vesting Date. For purposes of this Section 7, the prorated number of RSUs that may become Vested RSUs upon a Change in Control shall be equal to the number of RSUs granted hereunder times a fraction (not greater than one), in which the numerator is the number of full months completed from the Grant Date to the date of the consummation of the Change in Control and the denominator is 36.
8. Dividend Equivalents. Until the date on which the RSUs are settled for Shares (or cash in the case of RSUs deferred under the Company’s Executive Deferred Compensation Plan), and pursuant to the terms and conditions of this Agreement, the Grantee will be credited (in the manner described in the following sentences) on the books and records of the Company with an amount per each RSU equal to the amount per share of any cash dividends declared by the Board of Directors of the Company with a record date on or after the Grant Date on the outstanding
Shares (such amount, a “Dividend Equivalent”). Such Dividend Equivalents will be credited in the form of an additional number of RSUs. The additional number of RSUs will be equal to the aggregate amount of Dividend Equivalents credited under this Agreement on the respective dividend payment date divided by the average of the high and low prices per Share on the respective dividend payment date. The RSUs attributable to the Dividend Equivalents will be either settled or forfeited, as appropriate, under the same terms and conditions that apply to the other RSUs under this Award Agreement, including any action taken by the Committee. For the avoidance of doubt, if the Grantee defers settlement of any portion of the RSUs pursuant to the Executive Deferred Compensation Plan, then, during the deferral period, the Grantee’s stock account under the Executive Deferred Compensation Plan shall continue to be credited with Dividend Equivalents pursuant to this Section 8 until such deferred RSUs are settled for Shares or cash, as applicable, under the terms of the Executive Deferred Compensation Plan.
9. Continuous Employment. So long as the Grantee continues to be an employee of the Company or any of its Subsidiaries, the Grantee shall not be considered to have experienced a termination of employment because of: (a) any temporary leave of absence approved in writing by the Company or such Subsidiary; or (b) any change of duties or position (including transfer from one Subsidiary to another); provided, however, that, in the case of any change of duties or position that results in the Grantee no longer being an executive of the Company or a Subsidiary, the terms of Section 6(e) shall apply.
10. Delivery of Shares. Upon settlement of any RSUs under this Agreement, the Company will deliver to the Grantee (or the Grantee’s estate) the Shares to which the Grantee is entitled free and clear of any restrictions (except any restrictions under applicable securities laws or otherwise imposed under the Plan or Section 3 hereof).
11. Withholding. Upon settlement of the RSUs, the Company shall withhold a number of Shares (or amount of cash, if applicable) in an amount sufficient to satisfy all federal, state, and local taxes to be withheld in connection with the settlement of RSUs under this Agreement.
12. No Shareholder Rights. The Grantee shall have no shareholder rights (or rights as a beneficial owner), including no voting rights, with respect to any RSU or the Share underlying the RSU unless and until the Grantee receives the Share upon settlement of the RSU.
13. Recoupment. If the Grantee is or has been deemed to be, or becomes, an “officer” for purposes of Section 16 of the Exchange Act, this Agreement will be administered in compliance with Section 10D of the Exchange Act, any applicable rules or regulations promulgated by the Securities and Exchange Commission or any national securities exchange or national securities association on which the Shares may be traded, and subject to the Company’s Executive
Compensation Recoupment Policies, as amended (or succeeded) from time to time, or any other Company policy adopted pursuant to such law, rules, or regulations and this Agreement may be amended to further such purpose without the consent of the Grantee.
14. Termination of Agreement. This Agreement will terminate on the earliest of: (a) the date of the Grantee’s termination of employment with the Company, except if such termination of employment is due to death, Disability, Retirement, or a termination by the Company without Cause; (b) the date the RSUs are settled pursuant to the terms of this Agreement; or (c) if no RSUs have become Vested RSUs as of the Vesting Date, the Vesting Date. Any terms or conditions of this Agreement that the Company determines are reasonably necessary to effectuate its purposes shall survive the termination of this Agreement.
15. Miscellaneous Provisions.
(a) Adjustments. In the event of a corporate event or transaction described in Section 4.5 of the Plan, this Award and the RSUs granted hereunder shall be subject to mandatory adjustment as described in Section 4.5 of the Plan.
(b) Successors and Legal Representatives. This Agreement will bind and inure to the benefit of the Company and the Grantee, and their respective successors, assigns and legal representatives.
(c) Integration. This Agreement, together with the Plan, constitutes the entire agreement between the Grantee and the Company with respect to the subject matter hereof. Any waiver of any term, condition or breach thereof will not be a waiver of any other term or condition or of the same term or condition for the future, or of any subsequent breach. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern, except with respect to the Committee’s authority to adjust downward the number of RSUs that vest under this Agreement, as provided under Section 15(h) below.
(d) Notice. Any notice relating to this grant must be in writing, which may include an electronic writing.
(e) No Employment Right Created. Nothing in this Agreement will be construed to confer upon the Grantee the right to continue in the employment or service of the Company or any of its Subsidiaries, or to be employed or serve in any particular position therewith or affect any right which the Company or any of its Subsidiaries may have to terminate the Grantee’s employment or service with or without cause.
(f) Severability. In the event of the invalidity of any part or provision of this Agreement, such invalidity will not affect the enforceability of any other part or provision of this Agreement.
(g) Section Headings. The section headings of this Agreement are for convenience of reference only and are not intended to define, extend or limit the contents of the sections.
(h) Amendment. The terms and conditions of this Agreement may be modified by the Committee:
(i) in any case permitted by the terms of the Plan or this Agreement;
(ii) except with respect to an adjustment made pursuant to the last paragraph of this Section 15(h), with the written consent of the Grantee; or
(iii) without the consent of the Grantee if the amendment is either not materially adverse to the interests of the Grantee or is necessary or appropriate in the view of the Committee to conform with, or to take into account, applicable law, including either exemption from or compliance with any applicable tax law.
Notwithstanding any provision in this Agreement or the Plan to the contrary, the Committee shall retain the discretion to adjust the number of RSUs that vest under this Agreement without the Grantee’s consent, either on a formula or discretionary basis or a combination of the two, as the Committee determines in its sole discretion.
(i) Plan Administration. The Plan is administered by the Committee, which has full and exclusive discretionary power to interpret, implement, construe and adopt rules, forms and guidelines for administering the Plan and this Agreement. All actions, interpretations and determinations made by the Committee, the Board of Directors, or
any of their delegates as to the provisions of this Agreement and the Plan shall be final, conclusive, and binding on all persons and the Grantee agrees to be bound by such actions, interpretations and determinations.
(j) Governing Law. Except as may otherwise be provided in the Plan, this Agreement will be governed by, construed and enforced in accordance with the internal laws of the State of Ohio, without giving effect to its principles of conflict of laws. By accepting this Award, the Grantee agrees to the exclusive jurisdiction and venue of the courts of the United States District Court for the Northern District of Ohio or the Summit County (Ohio) Court of Common Pleas to adjudicate any and all claims brought with respect to this Agreement.
(k) Internal Revenue Code Section 409A. Notwithstanding anything in the Plan or this Agreement to the contrary, the Award of RSUs granted hereunder is intended to meet any applicable requirements for compliance under Code Section 409A and this Agreement shall be construed and administered accordingly. Notwithstanding anything in this Agreement to the contrary, if the RSUs become vested and settled upon the Grantee’s termination of employment (other than Retirement), payment with respect to the RSUs shall be delayed for a period of six months after the Grantee’s termination of employment if the Grantee is a “specified employee” as defined under Code Section 409A (as determined by the Committee) (each, a “Specified Employee”), if required pursuant to Code Section 409A. With respect to any Grantee: (i) who is eligible for Retirement prior to the Vesting Date; (ii) whose employment is terminated prior to the Vesting Date due to the Grantee’s Retirement; and (iii) who is a Specified Employee on the date of the Grantee’s termination of employment, payment with respect to all the Grantee’s RSUs shall be delayed for a period of six months after the Grantee’s termination of employment. If payment is delayed, the Shares shall be distributed within 60 days following the date that is the six-month anniversary of the Grantee’s termination of employment. If the Grantee dies during the six-month delay, the Shares shall be distributed to the Grantee’s estate within 60 days following the Grantee’s death. Notwithstanding any provision to the contrary herein, payments made with respect to this Award of RSUs may only be made in a manner and upon an event permitted by Code Section 409A, and all payments to be made upon a termination of employment hereunder may only be made upon a “separation from service” as defined under Code Section 409A. To the extent that any provision of this Agreement would cause a conflict with the requirements of Code Section 409A or would cause the administration of the RSUs to fail to satisfy the requirements of Code Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. In no event shall the Grantee, directly or indirectly, designate the calendar year of payment. If payment of the RSUs is subject to the execution of a Release, and if payment with respect to the RSUs that is subject to the execution of the Release could be made in more than one taxable year, payment
shall be made in the later taxable year. Notwithstanding anything in this Agreement to the contrary, the Company makes no representations or warranties as to the tax effects of payments made to the Grantee (or the Grantee’s estate) pursuant to this Agreement, and any and all tax consequences incident to such shall solely be the responsibility of the Grantee (or the Grantee’s estate).
(l) Data Privacy. In order to implement, administer and manage the Grantee’s participation in the Plan, the Company and its affiliates may hold certain personal information about the Grantee, including, but not limited to, the Grantee’s name, home address and telephone number, date of birth, social security number or other identification number, salary, nationality, job title, any Shares or directorships held in the Company or any affiliate, details of all Awards or any other entitlement to Shares awarded, canceled, exercised, vested, unvested or outstanding in the Grantee’s favor, for the exclusive purpose of implementing, administering and managing the Plan (collectively, the “Personal Data”).
The Grantee hereby explicitly and unambiguously consents to the collection, use and transfer, in electronic or other form, of the Grantee’s Personal Data as described above, as applicable, to the Company and its affiliates for the sole purpose of administering the Plan. The Grantee understands that Personal Data may be transferred to third parties assisting in the implementation, administration and management of the Plan, that these recipients may be located in the United States or elsewhere, and that the recipient’s country may have different data privacy laws and protections than the United States or the Grantee’s state of residence. The Grantee understands that the Grantee may request a list with the names and addresses of any potential recipients of the Personal Data by contacting the Executive Compensation group of Human Resources. The Grantee authorizes the recipients to receive, possess, use, retain and transfer the Personal Data, in electronic or other form, for the purposes of implementing, administering and managing the Grantee’s participation in the Plan, including any requisite transfer of such Personal Data as may be required to a broker or other third party with whom the Grantee may elect to deposit any Shares received upon vesting of the RSUs. The Grantee understands that Personal Data will be held only as long as is necessary to implement, administer and manage the Grantee’s participation in the Plan and to comply with Securities and Exchange Commission and/or NYSE reporting obligations, any other applicable law or regulation and any applicable document retention policies of the Company. The Grantee understands that the Grantee may, at any time, view Personal Data, request additional information about the storage and processing of Personal Data, require any necessary amendments to Personal Data or refuse or withdraw the consents herein, without cost, by contacting in writing the Executive Compensation group of Human Resources. The Grantee understands that refusal or withdrawal of consent may affect the Grantee’s ability to participate in the Plan or to realize benefits from the RSUs. For more information on the consequences of the Grantee’s refusal to consent or withdrawal of
consent, the Grantee understands that the Grantee may contact the Executive Compensation group of Human Resources.
(m) Signatures and Electronic Delivery. This Agreement may be executed electronically and in counterparts, each of which shall be deemed to be an original, and when taken together shall constitute one binding agreement. The Company may, in its sole discretion, deliver any documents related to current or future participation in the Plan by electronic means. The Grantee hereby consents to receive such documents by electronic delivery and agrees to participate in the Plan through an on-line or electronic system established and maintained by the Company or another third party designated by the Company.
[SIGNATURE ON FOLLOWING PAGE]
The Grantee acknowledges receipt of this Agreement and accepts and agrees with the terms and conditions stated above.
#AcceptanceDate# ____#Signature#______
(Date) (Signature of the Grantee)
EX-31.1
4
feq12025-ex311.htm
EX-31.1
Document
Certification
I, Brian X. Tierney, certify that:
1.I have reviewed this report on Form 10-Q of FirstEnergy Corp.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c.evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 30, 2025
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/s/ Brian X. Tierney |
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Brian X. Tierney |
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Chair, President and Chief Executive Officer |
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(Principal Executive Officer) |
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EX-31.1
5
jcplq12025-ex311.htm
EX-31.1
Document
Certification
I, W. Douglas Mokoid, certify that:
1.I have reviewed this report on Form 10-Q of Jersey Central Power & Light Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c.disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 30, 2025
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/s/ W. Douglas Mokoid |
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W. Douglas Mokoid |
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President and Director |
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(Principal Executive Officer) |
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EX-31.2
6
feq12025-ex312.htm
EX-31.2
Document
Certification
I, K. Jon Taylor, certify that:
1.I have reviewed this report on Form 10-Q of FirstEnergy Corp.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c.evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 30, 2025
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/s/ K. Jon Taylor |
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K. Jon Taylor |
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Senior Vice President, Chief Financial Officer and Strategy |
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(Principal Financial Officer) |
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EX-31.2
7
jcplq12025-ex312.htm
EX-31.2
Document
Certification
I, Teresa Reed, certify that:
1.I have reviewed this report on Form 10-Q of Jersey Central Power & Light Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c.disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 30, 2025
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/s/ Teresa Reed |
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Teresa Reed |
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Vice President, State Finance and Regulatory |
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(Principal Financial Officer) |
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EX-32
8
feq12025-ex32.htm
EX-32
Document
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
In connection with the Report of FirstEnergy Corp. (“Company”) on Form 10-Q for the period ended March 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ Brian X. Tierney |
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Brian X. Tierney |
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Chair, President and Chief Executive Officer |
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(Principal Executive Officer) |
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/s/ K. Jon Taylor |
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K. Jon Taylor |
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Senior Vice President, Chief Financial Officer and Strategy |
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(Principal Financial Officer) |
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Date: April 30, 2025
EX-32
9
jcplq12025-ex32.htm
EX-32
Document
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
In connection with the Report of Jersey Central Power & Light Company (“Company”) on Form 10-Q for the period ended March 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ W. Douglas Mokoid |
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W. Douglas Mokoid |
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President and Director |
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(Principal Executive Officer) |
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/s/ Teresa Reed |
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Teresa Reed |
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Vice President, State Finance and Regulatory |
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(Principal Financial Officer) |
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Date: April 30, 2025
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