EDGAR 10-K Filing

Company CIK: 1031296
Filing Year: 2025
Filename: 1031296_10-K_2025_0001031296-25-000006.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
The Companies
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 six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include more than 24,000 miles of transmission lines and two regional transmission operation centers. As of December 31, 2024, MP and AGC control 3,604 MWs of total capacity.
Regulated Electric Company Operating Subsidiaries
The Electric Companies’ combined service areas encompass approximately 65,000 square miles in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey, and New York, providing distribution services for over six million customers in an area with a population of approximately 14 million and include more than 9,900 miles of transmission lines. Total rate base was approximately $20.6 billion as of December 31, 2024.
OE owns property and does business as an electric public utility in Ohio, providing distribution services to approximately 1.1 million customers in central and northeastern Ohio, with a rate base of $2.1 billion as of December 31, 2024. OE has 1,061 employees and serves an area that has a population of approximately 2.4 million.
CEI owns property and does business as an electric public utility in Ohio, providing distribution services to approximately 0.8 million customers in northeastern Ohio, with a rate base of $1.7 billion as of December 31, 2024. CEI has 819 employees and serves an area that has a population of approximately 1.7 million.
TE owns property and does business as an electric public utility in Ohio, providing distribution services to approximately 0.3 million customers in northwestern Ohio, with a rate base of $0.6 billion as of December 31, 2024. TE has 324 employees and serves an area that has a population of approximately 0.7 million.
FE PA owns property and does business as an electric public utility in Pennsylvania and New York, providing distribution services to approximately 2.1 million customers in Pennsylvania and four thousand customers in Waverly, New York, with a rate base of $6.6 billion as of December 31, 2024. FE PA has 2,083 employees and serves an area that has a population of approximately 4.5 million. On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies.
JCP&L owns property and does business as an electric public utility in New Jersey, providing distribution services to approximately 1.2 million customers, as well as transmission services in northern, western, and east central New Jersey, with a combined rate base of $4.7 billion as of December 31, 2024. JCP&L has 1,296 employees and serves an area that has a population of approximately 2.8 million.
PE owns property and does business as an electric public utility in Maryland, Virginia, and West Virginia, providing distribution services to approximately 0.5 million customers in Maryland and West Virginia and provides transmission services in Maryland, West Virginia and Virginia. PE had a combined rate base of approximately $1.6 billion as of December 31, 2024. PE has 505 employees and serves an area that has a population of approximately 1.0 million.
MP owns property and does business as an electric public utility in West Virginia, providing distribution services to approximately 0.4 million customers, as well as generation and transmission services in northern West Virginia, with a combined rate base of $3.3 billion as of December 31, 2024. MP has 1,040 employees and serves an area with a population of approximately 0.8 million. MP is contractually obligated to provide power to PE to meet its load obligations in West Virginia. MP owns or contractually controls 3,604 MWs of net maximum generation capacity that is supplied to its electric utility business, including 24 MWs of Solar generation and 487 MWs of pumped-storage hydroelectric generation from its 16.25% undivided interest in the Bath County facility in Virginia through its wholly-owned subsidiary AGC.
Regulated Transmission Company Operating Subsidiaries
FET, a holding company and parent of ATSI, MAIT, TrAIL, and PATH, is a VIE of FE, which holds 50.1% of its issued and outstanding membership interests. Brookfield owns the remaining 49.9% of the issued and outstanding membership interests of FET. Through its subsidiaries, FET owns and operates high-voltage transmission facilities in the PJM Region and has a rate base of $8.5 billion. FET's subsidiaries are subject to regulation by FERC and applicable state regulatory authorities. FET and its subsidiaries have no direct employees. Each of these companies, however, relies on employees of their affiliates, including FESC, for the performance of necessary services. On January 1, 2024, PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET.
So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.
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., as 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.
ATSI owns high-voltage transmission facilities in PJM, which consist of 7,964 circuit miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV in Ohio and Pennsylvania and has a rate base of $4.3 billion as of December 31, 2024.
MAIT owns high-voltage transmission facilities in PJM, which consist of 4,287 circuit miles of transmission lines with nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV, 115 kV, 69 kV and 46 kV in Pennsylvania, and has a rate base of $2.8 billion as of December 31, 2024.
TrAIL owns high-voltage transmission facilities in PJM, which consists of 269 circuit miles of transmission lines with nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV, including a 500 kV transmission line extending approximately 150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection with VEPCO in northern Virginia, and has a rate base of $1.4 billion as of December 31, 2024.
PATH was a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012. 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.
KATCo owns high-voltage transmission facilities formerly owned by WP in PJM, which consist of 1,696 circuit miles of transmission lines with nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV, and 115 kV in Pennsylvania, and has a rate base of $0.5 billion as of December 31, 2024. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo. See Note 1, "Organization and Basis of Presentation," for more information.
Service Company
FESC has 5,166 employees and 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.
Segments Overview
During the first quarter of 2024, FirstEnergy’s segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. FirstEnergy’s reportable segments are as follows, and FirstEnergy continues to evaluate segment performance based on earnings attributable to FE from continuing operations:
•Distribution Segment, which consists of the Ohio Companies and FE PA;
•Integrated Segment, which consists of MP, PE and JCP&L; and
•Stand-Alone Transmission Segment, which consists of FE's ownership in FET and KATCo.
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission.
The Distribution segment, which consists of the Ohio Companies and FE PA, representing $11 billion in rate base as of December 31, 2024, 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, representing $9.6 billion in rate base as of December 31, 2024. 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 January and September 2024, representing 24 MWs of net maximum generating capacity. The remaining three sites, once completed, are expected to provide 26 MWs of additional net maximum generation capacity.
The Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, representing $5.3 billion in rate base as of December 31, 2024, includes transmission infrastructure owned and operated by the Transmission Companies and used to transmit electricity. The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains in the Stand-Alone Transmission segment. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and prior year results in the Stand-Alone Transmission segment reflect the earnings and results of those WP transmission assets.
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. 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 December 31, 2024, Corporate/Other had approximately $6.1 billion of external FE holding company debt.
Regulatory Accounting
FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Electric Companies and the Transmission Companies as their rates are established by third-party regulators with the authority to set binding rates that are cost-based and can be charged to and collected from customers.
The Electric Companies and the Transmission Companies recognize, as regulatory assets and regulatory liabilities, costs that FERC and the various state utility commissions, as applicable, have authorized for recovery from or return to customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets and regulatory liabilities would have been charged or credited to income as incurred. All regulatory assets and liabilities are expected to be recovered from or returned to customers. Based on current ratemaking procedures, the Electric Companies and the Transmission Companies continue to collect cost-based rates for their distribution and transmission services; accordingly, it is appropriate that the Electric Companies and the Transmission Companies continue the application of regulatory accounting to those operations. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded regulatory assets and liabilities are removed from the balance sheet in accordance with GAAP.
State Regulation and Federal Regulation
The following table summarizes the allowed ROE and the aggregate actual ROE of the Electric Companies and Transmission Companies as determined for regulatory purposes as of and for the year ended December 31, 2024:
Segment Entity/State Allowed ROE Actual ROE
Stand-Alone Transmission FET 9.88%(1) - 12.7%
10.4%(2)
KATCo 9.6% 10.45%
Integrated Maryland 9.5% - Distribution
10.45% - Transmission 8.3%
New Jersey
9.6% - Distribution
10.2% - Transmission 9.3%
West Virginia 9.8% 8.4%
Distribution Ohio 10.8%(3)
4.7%(3)
Pennsylvania Settled(4)
9.0%
(1) Reflects a 0.5% reduction to ATSI's 10.38% approved ROE due to the January 2025 Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership (see Transmission ROE Incentive: OCC v. ATSI, et al. below)
(2) FET ROE is a weighted average allowed ROE of ATSI, MAIT and TrAIL
(3) As filed on July 31, 2024, in pending base rate case before revenue adjustment
(4) Commission-approved settlement agreement did not disclose ROE
See "Outlook - State Regulation" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
See "Outlook - FERC Regulatory Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Environmental Matters
See "Outlook - Environmental Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Capital Requirements
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction and other investment expenditures, scheduled debt maturities and interest payments, dividend payments and potential contributions to its pension plan. See "Capital Resources and Liquidity" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Supply Plan
Supply Chain
Economic conditions have stabilized across numerous material categories, but not all lead times have returned to pre-pandemic levels. Several key suppliers have seen improvements with capacity, but FirstEnergy continues to monitor the situation as demand increases across the industry, including due to data center usage. Inflationary pressures have moderated, which has improved the cost of materials, but certain categories have remained elevated. 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 FirstEnergy’s results of operations, cash flow and financial condition.
In February 2025, the new U.S. presidential administration announced the imposition of widespread and substantial tariffs on imports, with plans for additional tariffs to potentially be adopted in the future. Although certain of these tariffs were subsequently temporarily stayed, the situation is dynamic and subject to rapid change. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on FirstEnergy's results of operations, cash flow and financial condition.
Default Service
Certain of the Electric Companies have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. These default service plans vary by state and service territory, and volume of sales can vary depending on the level of shopping that occurs. JCP&L’s default service, or BGS supply, is secured through a statewide competitive procurement process approved by the NJBPU. Default service for the Ohio Companies, FE PA and PE's Maryland jurisdiction are provided through a competitive procurement process approved by the PUCO (under the current ESP), PPUC (under the Default Service Plan) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Electric Companies’ service areas, the Utility serving that area may need to procure the required power in the market in their role as the default load serving entity. West Virginia electric generation continues to be regulated by the WVPSC.
Fuel Supply
MP has coal contracts with various terms to purchase approximately 3 million tons of coal for the year 2025, which, along with its 2024 year-end inventory levels, accounts for approximately 80% of its forecasted 2025 coal requirements. MP has the ability to acquire additional tonnage through options available in its current contracts, as well as purchases through the spot market. The contracts expire at various times through 2027. This contracted coal is produced primarily from mines located in Pennsylvania and West Virginia. In order to meet emission requirements, MP holds contracts for a variety of reagents expiring at various times through 2026, as well as the ability to purchase additional reagents through the spot market. Additionally, MP is granted emission allowances by the EPA and purchases additional allowances as needed to meet emission requirements. See "Outlook - Environmental Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information pertaining to the impact of increased environmental regulations on fuel supply.
System Demand
The maximum hourly demand in 2024, 2023 and 2022 for each of the Electric Companies was:
For the Years Ended December 31,
System Demand 2024 2023 2022
(In MWs)
CEI 3,971 3,868 4,266
FE PA1
10,404 10,058 10,255
JCP&L 6,184 5,731 6,122
MP 2,096 2,051 2,124
OE 5,582 5,192 5,652
PE 3,860 3,103 3,514
TE 2,074 2,220 2,277
(1) On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity.
Regional Reliability
All of FirstEnergy's facilities are located within the PJM Region and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of NERC in accordance with a delegation agreement approved by FERC.
Competition
Within FirstEnergy’s Electric Companies' distribution business, there generally is no competition for electric distribution service in the Electric Companies’ respective service territories in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. Additionally, pursuant to FERC’s Order No. 1000 and subject to state and local siting and permitting approvals, non-incumbent developers can compete for certain PJM transmission projects in the service territories of certain of FirstEnergy’s Electric Companies' providing transmission services and the Transmission Companies. This has resulted in additional competition to build transmission facilities in the respective service territories while also allowing the opportunity to seek to build facilities in non-incumbent service territories.
Seasonality
The sale of electric power is generally a seasonal business, and weather patterns can have, and have in the past had, a material impact on FirstEnergy’s Electric Companies' operating results. Demand for electricity in our service territories historically peaks during the summer and winter months. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales, and consequently, lower revenue, earnings and cash flow.
Human Capital
FirstEnergy focuses on a number of human capital resources, measures and objectives in managing its business, including through striving to achieve its core values.
FirstEnergy believes that creating a sense of belonging among our employees positions the company to deliver better service to customers, strengthen operational performance, and help create a work environment where employees feel valued and respected. FirstEnergy remains focused advancing a culture of belonging for employees.
During 2024, FirstEnergy continued to promote these values by:
•Sponsoring a council of select senior management and other leaders and influential employees across the company, who work together to promote our core values throughout the workforce;
•Sharing the results of our most recent employee engagement survey designed to capture our employees’ perspectives on their work experience and progress toward embracing a more welcoming culture; and
•Supporting multiple employee business resource groups, known as "EBRGs," to further support our values through networking, mentoring, coaching, recruiting, development and community outreach. There are currently 9 EBRGs across 21 chapters, which are open to all employees.
Safety
Safety is an unwavering core value of FirstEnergy. FirstEnergy employees have the power and responsibility to keep each other safe and eliminate life-changing events, which are injuries that have life-changing impacts or fatal results. Safety metrics, such as injuries that result in days away or restricted time and life-changing events, are regularly monitored, internally reported, and included in FirstEnergy’s annual incentive compensation program to reinforce that a safe work environment is crucial to FirstEnergy’s success.
FirstEnergy continues to focus on mitigating life-changing event exposure to strengthen FirstEnergy’s safety-first culture and drive safer decisions from an engaged workforce who puts safety first. FirstEnergy continues to embed its "Leading with Safety" learnings where leaders and employees receive safety training and reinforcement of exposure control concepts that are designed to improve job site exposure identification, communication and mitigation to ultimately prevent life changing events.
Employee Development
FirstEnergy’s employees are empowered to take ownership of their careers with increased transparency into FirstEnergy’s internal and external hiring process and availability of tools and processes that support career management, talent reviews, succession planning and leadership selection. FirstEnergy is committed to preparing its high-performing workforce for the future and helping employees reach their full potential, which includes developing employee skills and competencies and preparing aspiring, emerging and experienced leaders for future leadership responsibilities.
Understanding FirstEnergy’s rapidly changing industry and strategy is key to its employees’ ability to support FirstEnergy’s mission and meet its customers’ evolving needs. Key FirstEnergy development programs include:
•Talent management, which includes a commitment to transparency in career management and development opportunities, consistent with FirstEnergy’s core values;
•A mentoring program that gives employees the opportunity to select a mentor from within the organization to promote enhanced learning, teamwork and collaboration;
•Leadership development opportunities that include training for new supervisors and managers, experienced leader programming and coaching, aspiring leader programs that build leadership capabilities for employees who are ready near-term leadership roles; and external partnership with the Center for Creative Leadership® and BeingFirst® for senior and executive leadership development;
•Educational opportunities through FirstEnergy’s "Educate to Elevate" program, which provides access to post-secondary education and a path to both associate’s and bachelor’s degrees for employees; and
•Workforce development programs that include an apprentice line worker program designed to attract technical entry-level talent to FirstEnergy.
Compensation and Benefits
FirstEnergy’s total rewards program is designed to attract, motivate, retain and reward employees for their role in the success of FirstEnergy. The base pay program is designed to balance an employee’s value to FirstEnergy in a manner that is commensurate with comparable jobs at peer companies. FirstEnergy aims to ensure that its internal policies and processes support pay equity.
The annual incentive compensation program is designed to align compensation with the achievement of near-term corporate and business unit objectives, as well as outstanding individual performance. Additionally, FirstEnergy’s long-term incentive compensation program is designed to reward eligible leaders for FirstEnergy’s achievement of longer-term goals intended to drive shareholder value and growth. In addition to base pay and incentive compensation plans, FirstEnergy offers a comprehensive benefits program, including healthcare, dental, prescription, vision, a 401(k) savings plan and a defined benefit pension plan to eligible employees.
Employees and Collective Bargaining Agreements
As of December 31, 2024, FirstEnergy had 12,294 employees, all of whom were located in the United States as follows:
Total
Employees Bargaining
Unit
Employees
FESC 5,166 521
CEI 819 570
FE PA 2,083 1,536
JCP&L 1,296 992
MP 1,040 396
OE 1,061 666
PE 505 246
TE 324 249
Total 12,294 5,176
As of December 31, 2024, the IBEW, the UWUA and the OPEIU unions collectively represented approximately 40% of FirstEnergy’s employees. There are currently 15 collective bargaining agreements between FirstEnergy’s subsidiaries and its unions, which have multi-year contracts. In 2024, FirstEnergy’s subsidiaries reached new collective bargaining agreements with IBEW Local 1289, IBEW Local 459 and OPEIU 792. One collective bargaining agreement was set to expire in 2025, with a settlement reached in January 2025, representing approximately 3% of FirstEnergy’s employees.
Information About Our Executive Officers (as of February 27, 2025)
Name Age Positions Held During Past Five Years Dates
Brian X. Tierney 57 Chair, President and Chief Executive Officer (A) 2024-Present
President and Chief Executive Officer (A) 2023-2024
President and Chief Executive Officer (B) 2023-Present
Blackstone Infrastructure Partners, Senior Managing Director 2021-2023
AEP, Executive Vice President - Strategy 2021
AEP, Executive Vice President and Chief Financial Officer *-2020
Hyun Park 63 Senior Vice President and Chief Legal Officer (A) (B) 2021-Present
Senior Vice President and General Counsel (C) (D) 2021-2022
LimNexus, Partner and General Counsel *-2021
Jason J. Lisowski 43 Vice President, Controller and Chief Accounting Officer (A) (B) *-Present
Vice President and Controller (C) (E) *-Present
K. Jon Taylor 51 Senior Vice President, Chief Financial Officer and Strategy (A) (B) 2021-Present
Senior Vice President and Chief Financial Officer (C) (E) 2020-2024
Senior Vice President and Chief Financial Officer (A) (B) 2020-2021
Vice President, Utility Operations (B) *-2020
President (D) *-2020
Toby L. Thomas 53 Chief Operating Officer (A) (B) 2023-Present
AEP, Senior Vice President 2021-2023
Indiana Michigan Power, President and Chief Operating Officer *-2021
A. Wade Smith 60 President, FirstEnergy Utilities (A) (B) 2023-Present
Puget Sound Energy, Inc., Executive Vice President and Chief Operating Officer 2022-2023
Pacific Gas & Electric, Senior Vice President 2021-2022
AEP, Senior Vice President *-2021
* Indicates position held at least since January 1, 2020
(A) Denotes position held at FE
(B) Denotes position held at FESC
(C) Denotes position held at the Ohio Companies, the Pennsylvania Companies(1), MP, PE, FET, ATSI, MAIT, TrAIL and KATCo.
(D) Denotes position held at AGC
(E) Denotes position held at FE PA(1)
(1) On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity. Upon consolidation, executive officers of the Pennsylvania Companies were named as executive officers of FE PA.
FirstEnergy Website and Other Social Media Sites and Applications
FirstEnergy's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports, and all other documents filed with or furnished to the SEC pursuant to Section 13(a) of the Exchange Act are made available free of charge on 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.
FirstEnergy has adopted, and posted on its website at www.firstenergycorp.com/responsibility, a Code of Conduct, The Power of Integrity, which applies to all employees, including FirstEnergy’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The Code of Conduct is available, without charge, upon written request to the Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. Within the time period required by the SEC, FirstEnergy will post on its website any substantive amendment to the Code of Conduct and any waiver applicable to an FE director or FE executive officer.
These SEC filings are posted on the website as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Additionally, FirstEnergy routinely posts additional important information, including press releases, investor presentations, investor factbooks and notices of upcoming events under the "Investors" section of FirstEnergy’s website and recognizes FirstEnergy’s website as a channel of distribution to reach public investors and as a means of disclosing (including initially or exclusively) material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and Rich Site Summary feeds on the “Investors” page of FirstEnergy’s website. FirstEnergy also uses X (the social networking site formerly known as Twitter®), LinkedIn®, YouTube® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s website, X (the social networking site formerly known as Twitter®) handle, LinkedIn® profile, YouTube® channel or Facebook® page, and any corresponding applications of those sites, shall not be deemed incorporated into, or to be part of, this report.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management regularly evaluates the most significant risks of its businesses and reviews those risks with the FE Board and appropriate Committees of the FE Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we consider material. The risks that we face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our business, financial condition, results of operations, liquidity or cash flows. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. These risk factors should be read in conjunction with Item 1, "Business,” Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business, financial condition, results of operations, liquidity or cash flows.
Risks Associated with Damage to Our Reputation and HB 6 Related Litigation and Investigations
HB 6-related investigations and litigation could have a material adverse effect on our reputation, business, financial condition, results of operations, our ability to access capital, liquidity or cash flows.
On July 21, 2021, we entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the previously disclosed U.S. Attorney’s Office investigation into us relating to our lobbying and governmental affairs activities concerning HB 6. Under the DPA, we paid a $230 million monetary penalty in 2021 and agreed to the filing of a criminal information charging FirstEnergy with one count of conspiracy to commit honest services wire fraud.
As of July 22, 2024, we successfully completed the obligations required within the three-year term of the DPA. Under the DPA, and until the conclusion of any related investigation, criminal prosecution and civil proceeding brought by the U.S. Attorney’s Office, we have an obligation to continue (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by us to be 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 for the S.D. Ohio of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office for the S.D. Ohio. In accordance with the DPA, these obligations will continue until the completion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office related to the conduct set forth in the DPA’s statement of facts, including the January 17, 2025 indictment against two former FirstEnergy senior officers, described below in “Outlook-Other Legal Proceeding - United States 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.
If we are found to have breached the terms of the DPA, the U.S. Attorney’s Office may elect to prosecute, or bring a civil action against, us for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have a material adverse impact on our reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as our consolidated financial statements. Failure to comply with the DPA, including alleged failures to comply with anti-corruption and anti-bribery laws, may also result in a breach of certain covenants contained in our credit agreements and could result in an event of default under such agreements, and we would not be able to access our credit facilities for additional borrowings and letters of credit during the existence of any such default.
Following the announcement by the U.S. Attorney’s Office for the S.D. Ohio of the investigation surrounding HB 6 in July 2020, certain of our stockholders and customers filed several lawsuits against us and certain current and former directors, officers and other employees, including the federal securities class action litigation In re FirstEnergy Corp. Securities Litigation (Federal District Court, S.D. Ohio). We believe that it is probable that FE will incur a loss in connection with the resolution of In re FirstEnergy Corp. Securities Litigation. Given the ongoing nature and complexity of such litigation, we cannot yet reasonably estimate a loss or range of loss that may arise from its resolution. However, if it is resolved against us substantial monetary damages could result and our reputation, business, financial condition, results of operations, liquidity or cash flows may be materially adversely affected.
The litigation related to HB 6 could divert management’s focus and have resulted in, and could continue to result in, substantial expenses, and the commitment of substantial corporate resources. The outcome, duration, scope, result or related costs of the in securities class action litigation In re: FirstEnergy Corp. Securities Litigation discussed above, are inherently uncertain. Therefore, any of these risks could impact us significantly beyond expectations. See Note 15, "Commitments, Guarantees and Contingencies" of the Notes to Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates.”
These matters are likely to continue to have an adverse impact on the trading prices of our securities, which could be material. See Note 15, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements, for additional details on the government investigations and subsequent litigation surrounding HB 6.
The HB 6 related state regulatory investigations could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.
There are several ongoing HB 6 related state regulatory matters including, but not limited to, the below HB 6-related matters, each of which was stayed for a third time by the PUCO on August 23, 2023, at the request of the U.S. Attorney for the Southern District of Ohio, for a period of an additional six months. The stay on the following matters was lifted on February 26, 2024:
•On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On February 26, 2024, this proceeding was consolidated 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 May 13, 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. On September 30, 2024, the third-party auditor’s report was filed. See ”Outlook - State Regulation - Ohio” below for additional information regarding the auditor’s findings. Comments have been filed on the audit report and remain pending with the PUCO;
•On December 30, 2020, the PUCO directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. The auditor’s report was filed on January 14, 2022, and the parties submitted final comments and responses in the second quarter 2022. See ”Outlook - State Regulation - Ohio” below for additional information regarding the auditor’s findings. On February 26, 2024, this proceeding was consolidated 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 May 13, 2025; and
•On March 10, 2021, the PUCO expanded the scope of an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020 to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On February 26, 2024, this proceeding was consolidated 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 May 13, 2025.
See Note 14, "Regulatory Matters" of the Notes to Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates” for additional details on the state regulatory investigations surrounding HB 6.
While FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway, FirstEnergy shareholders in particular are at risk of being adversely impacted because the rates our Electric Companies and Transmission Companies are allowed to charge may be decreased as a result of actions taken by a regulator to which our Electric Companies and Transmission Companies are subject to jurisdiction, whether as a result of the DPA, any failure to have complied with anti-corruption laws, or otherwise.
We are unable to predict the adverse impacts of such regulatory matters, including with respect to rates, and, therefore, any of these risks could impact us significantly beyond expectations. Moreover, we are unable to predict the potential for any additional regulatory actions, any of which could exacerbate these risks or expose us to adverse outcomes in pending or future rate cases, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.
Damage to our reputation may arise from numerous sources making us vulnerable to negative customer perception, adverse regulatory outcomes, or other consequences, which could materially adversely affect our business, results of operations and financial condition.
Our reputation is important. Damage to our reputation could materially adversely affect our business, results of operations and financial condition. Such damage may arise from numerous sources further discussed generally within these risk factors. Any damage to our reputation, either generally or as a result of the foregoing, may lead to negative customer perception, which may make it difficult for us to compete successfully for new opportunities, or could adversely impact our ability to launch new sophisticated technology-driven solutions to meet our customer expectations. A damaged reputation could further result in FERC, the state public utility commissions, and other regulatory and legislative authorities being less likely to view us in a favorable light and could negatively impact the rates we charge customers or otherwise cause us to be susceptible to unfavorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements.
Risks Associated with the Execution of Our Strategic Initiatives
If our cost saving initiatives do not achieve the expected benefits, there could be negative impacts to FirstEnergy's business, results of operations and financial condition.
FirstEnergy is engaged in an ongoing effort to create a culture of continuous improvement to strategically reduce our operating expenditures and continually reinvest in a more diverse capital program in support of our long-term strategy. FirstEnergy leverages opportunities to reduce costs - such as filling only critical positions, implementing our facility optimization plans, and exploring other additional, sustainable opportunities, such as reducing contractor spend. There can be no assurance that implementation of our continuous improvement culture will allow us to realize the anticipated benefits to our business, results of operations and financial condition in a timely manner, if at all.
Our ability to achieve the continued benefits from our cost saving initiatives is subject to many estimates and assumptions as well as our ability to hire, recruit and retain an appropriately qualified workforce and implement a culture of continuous improvement. FirstEnergy could experience unexpected delays and business disruptions resulting from supporting these initiatives, decreased productivity, and higher than anticipated costs, any of which may impair our ability to reduce operating expenditures and to achieve anticipated results or otherwise harm FirstEnergy's business, results of operations and financial condition.
Risks Associated with Regulation of Our Distribution and Transmission Businesses
Our ability to grow our distribution and transmission businesses is subject to numerous risks and events, many of which are outside of our control.
Our ability to capitalize on investment opportunities available to our transmission business depends, in part, on successful recovery of our transmission investments. Factors that may affect rate recovery of our transmission investments include: (1) FERC’s timely approval of rates to recover such investments; (2) whether the investments are included in PJM's Regional Transmission Expansion Plan; (3) FERC's evolving policies with respect to incentive rates for transmission assets; (4) FERC's evolving policies with respect to the calculation of the base ROE component of transmission rates; (5) consideration and potential impact of the objections of those who oppose such investments and their recovery; and (6) timely development, construction, and operation of the new facilities.
Our ability to capitalize on investment opportunities available to our distribution business depends, in part, on any future distribution rate cases or other filings seeking cost recovery for distribution system enhancements in the states where our Electric Companies operate, including maintaining the affordability of the rates charged to customers. Any denial of, or delay in, the approval of any future distribution or transmission rate requests could restrict us from fully recovering our cost of service, may impose risks on the distribution and transmission operations, and could have a material adverse effect on our regulatory strategy, results of operations and financial condition.
State rate regulation may delay or deny full recovery of costs and impose risks on our operations. Any denial of or delay in cost recovery could have an adverse effect on our business, results of operations, liquidity, cash flows and financial condition.
The retail rates for each of the Electric Companies are set by each of its respective regulatory agency for utilities in the state in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC - through traditional, cost-based regulated utility ratemaking. As a result, any of the Electric Companies may not be permitted to recover its costs and, even if it is able to do so, there may be a significant delay between the time it incurs such costs and the time it is allowed to recover them. Factors that may affect outcomes in the distribution rate cases include, but are not limited to: (i) the value of plant in service; (ii) authorized rate of return; (iii) capital structure (including hypothetical capital structures); (iv) depreciation rates; (v) the allocation of shared costs, including consolidated deferred income taxes and income taxes payable across the Electric Companies; (vi) regulatory approval of rate recovery mechanisms for capital investment spending programs; and (vii) the accuracy of forecasts used for ratemaking purposes in "future test year" cases.
FirstEnergy can provide no assurance that any base rate request filed by any of the Electric Companies will be granted in whole or in part. Any denial of, or delay in, any base rate request could restrict the applicable utility from fully recovering its costs of service, may impose risks on its operations, and may negatively impact such Electric Company’s results of operations, cash flows and financial condition. In addition, to the extent that any of the Electric Companies seek an increase in rates, third-party pressure may be exerted on the applicable legislators and regulators to take steps to control rate increases, including through some form of rate increase moderation, reduction or freeze. Any related public discourse and debate, including with respect to the HB 6 litigation, can increase uncertainty associated with the regulatory process, the level of rates and revenues that are ultimately obtained, and the ability of the Electric Company to recover costs. Such uncertainty may restrict operational flexibility and resources, reduce liquidity and increase financing costs.
Federal rate regulation may delay or deny full recovery of costs and impose risks on our operations. Any denial or reduction of, or delay in cost recovery could have an adverse effect on our business, results of operations, cash flows and financial condition.
FERC policy currently permits recovery of prudently incurred costs associated with cost-of-service-based wholesale power rates and the expansion and updating of transmission infrastructure within its jurisdiction. FERC’s policies on recovery of transmission costs continue to evolve, evidenced by ongoing proceedings to determine an appropriate ROE methodology to determine transmission ROEs, and to determine whether FERC’s existing policies on transmission rate incentives should be revised. If FERC were to adopt a different policy regarding recovery of transmission costs or if there is any resulting delay in cost recovery, our strategy of investing in transmission could be adversely affected. If FERC were to lower the rate of return it has authorized for FirstEnergy's cost-based wholesale power rates or transmission investments and facilities, it could reduce future earnings and cash flows, and adversely impact our financial condition.
Complex and changing federal, state and local government regulations and actions, including those associated with rates, could have a negative impact on our business, financial condition, results of operations and cash flows.
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, by federal executive orders or otherwise, have in the past and could in the future require us to incur additional costs, which could be substantial, or change the way we conduct our business, and therefore could have a material adverse impact on our results of operations and financial condition.
We could be subject to higher costs and/or penalties related to mandatory reliability standards set by NERC/FERC or changes in the rules of organized markets, which could have an adverse effect on our financial condition.
Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased investments. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1.5 million per day for failure to comply with these mandatory electric reliability standards.
In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.
We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.
As a member of PJM, which is an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in PJM’s market, as well as those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by its members.
Risks Related to our Business Operations
Demand for electricity within our service territory could exceed supply capacity, resulting in negative impacts to FirstEnergy’s reputation, results and financial condition, particularly if our systems are not performing as anticipated.
Recent industry projections reflect the potential for significant growth in energy demand over the next decade. This could be exacerbated if additional generation resources are not available to meet increased demand in the future. For example, data centers have substantially larger load requirements than typical residential or commercial users. New data centers or increase in demand for existing data centers located in our service territories could increase load requirements substantially over the next several years, thereby increasing the aggregate load obligations of the Electric Companies. A need to serve the load obligations of these data centers, which could be up to 5,575 MWs through 2029, has the potential to adversely impact our business, results of operations, financial condition, or cash flows.
We continue to evaluate the potential impacts of the development, construction, and operation of new data centers in our service territories and will continue to evaluate potential mitigants to these risks. FirstEnergy cannot predict whether the data centers under consideration will ever commence operations or the size of the load obligations of those that do become operational.
Competitive market forces or adverse regulatory actions may require FirstEnergy to purchase capacity and energy from the market or build additional resources to meet customers’ energy needs in an expedited manner. If that occurs, we may see opposition to recovery of these additional costs and could experience a lag between when costs are incurred and when regulators permit recovery in rates. These situations could have negative impacts on results of operations and cash flows.
Furthermore, in the event of electricity shortages, our ability to maintain service reliability may be compromised, which could adversely affect our financial performance, customer satisfaction, and compliance with regulatory requirements.
The hazardous activities associated with generation and distribution of electricity could adversely impact our results of operations and financial condition.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to naturally occurring risks, such as earthquakes, floods, lightning, wildfire, hurricanes and wind, other hazards, such as fire, explosion, electrocution, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or actions of third parties or other external events. The identification, control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties.
Our business is affected by variations in weather and severe weather conditions.
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when seasonal weather conditions are milder. For example, in 2024, heating degree days in 2024 were 1% below 2023 and 15% below normal.
In addition, severe weather, such as tornadoes, hurricanes, ice or snowstorms, droughts, high winds or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period and could have an adverse effect on our financial condition and results of operations, which adverse effects could be further exacerbated by an increased frequency of such severe weather events.
Cyber-attacks, electronic or physical data security breaches and other disruptions to our information technology systems, or those of third parties we are connected to or do business with, could compromise our business operations, critical and proprietary information and employee and customer data, which could have a material adverse effect on our business, results of operations, financial condition and reputation.
In the ordinary course of our business, we depend on information technology systems that utilize sophisticated operational systems and network infrastructure to run all facets of our generation, transmission and distribution services. Additionally, we store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks. We may also need to provide sensitive data to vendors and service providers who require access to this information. The secure maintenance of information and information technology systems is critical to our operations.
Over the last several years, there has been an increase in the frequency of cyber-attacks by terrorists, hackers, international activist organizations, foreign governments and individuals. These and other unauthorized parties may attempt to gain access to our network systems or facilities, or those of third parties with whom we do business, including directly through our network infrastructure or through fraud, trickery, or other forms of deception against our employees, contractors and temporary staff. Additionally, our information and information technology systems and those of our vendors and service providers may be increasingly vulnerable to data security breaches, damage and/or interruption due to viruses, ransomware, unauthorized physical access, theft of access devices, human error, malfeasance, faulty password management or other malfunctions and disruptions. Further, hardware, software, or applications we develop or procure from third parties may contain defects in design or manufacture or other problems that could unexpectedly compromise information and/or security.
As a source of critical infrastructure, the energy industry is at heightened threat of cyber-attacks, which are becoming increasingly more difficult to anticipate and prevent due to their rapidly evolving nature. We cannot anticipate, detect, or implement fully preventive measures against all cybersecurity threats because the techniques used are increasingly sophisticated and constantly evolving and in some cases, assisted by artificial intelligence.
In addition, the increased use of smartphones, tablets, and other wireless devices, as well as ongoing remote work-from-home arrangements, may also heighten these and other operational risks.
Our generation, transmission and distribution infrastructure, as well as the transmission facilities of third parties with whom we are interconnected, may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat security measures and gain access to our information technology systems may be made. As our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by cyber-attacks or other unexpected or uncontrollable events occurring on the systems of such third parties.
Any actual or perceived cyber-attack, data security breach, damage, interruption and/or defect could: (i) disable our generation, transmission and/or distribution services for a significant period of time; (ii) delay development and construction of new facilities or capital improvement projects; (iii) adversely affect our customer operations; (iv) expose us to increased risk of lawsuits; (v) expose us to increased risk of regulatory penalties; (vi) expose us to increased risk of loss of potential or existing customers; (vii) expose us to increased risk of damage relating to loss of proprietary information; (viii) corrupt data; and/or (ix) result in unauthorized access to the information stored in our data centers and on our networks and those of our vendors and service providers, including company proprietary information, supplier information, employee data and personal customer data, causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in economic loss and liability and harmful effects on the environment and human health, including loss of life.
As cyber threats continually evolve and become more difficult to detect and successfully defend against, there can be no assurance that we can implement or maintain adequate preventive measures, accurately assess the likelihood of a cyber-incident or quantify potential liabilities or losses. Also, we may not discover any data security breach and loss of information for a significant period of time after the data security breach occurs, particularly when the breach has occurred on the systems of our vendors and service providers.
For all of these reasons, any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the loss of confidential, sensitive and proprietary information, including but not limited to personal information of our customers, employees, suppliers, vendors and other third parties, the use of significant management resources, legal claims or proceedings, regulatory penalties, significant remediation costs, increased regulation, increased capital costs, increased insurance costs, increased protection costs for enhanced cyber security systems or personnel, and/or damage to our reputation, all of which could materially adversely affect our business, results of operations, financial condition and reputation.
Our insurance coverage may not provide protection against all significant losses and our ability to obtain insurance coverage, as well as the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.
If we cannot or do not obtain adequate insurance coverage, we may be required to pay costs associated with adverse future events. Through a combination of third-party and self-insurance, we have a comprehensive insurance program in place to provide coverage for various types of risks, including severe weather or other natural disasters, war, terrorism, cyber incidents, liability claims against us, or a combination of other significant unforeseen events that could impact our operations. However, insurance coverage may not continue to be available or may not be available at rates or on terms similar to those presently available to us. Our ability to obtain insurance and the terms of any available insurance coverage could be materially adversely affected by the financial condition of insurers, the impacts of actual or perceived climate-related events, as well as international, national, state, local or company-specific events.
There may be some instances in which we are not fully insured against all significant losses. A loss for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and prospects.
Macroeconomic conditions that are beyond our control, such as government fiscal policy, tariffs, recessions, inflation and interest rate pressures, may negatively impact our financial condition, results of operations, liquidity, and cash flows.
Economic conditions, including those that may arise from government fiscal policy, tariffs, recessions, inflationary and interest rate pressures, may impact the demand for electricity and, therefore, any decline in economic conditions could lead to declines in the demand for electricity, which would reduce our revenues. Prices for equipment, materials, supplies, employee labor contractor services, together with the cost of variable-rate debt, have increased in recent years and could continue to increase in 2025 and beyond. Long-term inflationary pressures may result in such prices continuing to increase more quickly than expected. Inflation increases costs for labor, materials and services, and we may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely impact our financial condition, results of operations, liquidity, and cash flows.
We have near-term exposure to interest rates from outstanding short-term indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise long-term debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets, as well as the U.S. Federal Reserve's interest rate policies, have resulted in volatile interest rates on new publicly issued debt securities and increased costs for variable interest rate debt securities. Disruptions in capital and credit markets, or the Federal Reserve Board's interest rate policies, could result in volatile interest rates on new publicly issued debt securities and increase our financing costs and adversely affect our results of operations, cash flows and liquidity. Also, interest rates could change as a
result of economic or other events that are beyond the control of our risk management processes. As a result, we cannot always predict the impact that our risk management decisions may have if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations, cash flows and liquidity.
Continued supply chain disruptions could have an adverse effect on our results of operations, cash flow and financial condition.
We continue to experience supply chain challenges due to economic conditions that developed during the COVID-19 pandemic and have continued in the years since, with order lead times increasing across numerous material categories, some of which remained elevated through 2024 and into 2025. The situation is fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition. Such disruptions could be exacerbated by unstable or uncertain macroeconomic conditions, including inflationary pressures. Any significant disruption or increased costs arising from these pressures on our suppliers may inhibit our access to, or require us to spend more money to source, certain products or that we use in our operations.
Furthermore, change or uncertainty in U.S. policies or the policies of other countries and regions in which our suppliers do business, including any changes or uncertainty with respect to U.S. or international trade policies or tariffs, could also disrupt our key suppliers’ operations. The presidential administration has taken action in 2025 to impose substantial new or increased tariffs. Any widespread imposition of new or increased tariffs could have an adverse effect on our results of operations, cash flow and financial condition. New or increased tariffs could also negatively affect U.S. national or regional economies, which also could negatively impact our business and results of operations.
We are subject to financial performance risks from regional and general economic cycles as well as data centers and heavy industries such as shale gas, automotive, chemical and steel.
Our business follows economic cycles. The regional economy in which our Electric Companies operate is influenced by conditions in industries in our business territories, e.g., data centers, shale gas, automotive, chemical, steel and other heavy industries, and as these conditions and resultant demand of those industries for electricity generation changes, our revenues will be impacted.
We are subject to risks arising from the operation of our power plants and transmission and distribution equipment which could reduce revenues, increase expenses and have a material adverse effect on our business, financial condition and results of operations.
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, human error in operations or maintenance, acts of terrorism or sabotage, cyber-attacks, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and operational performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Capital investments and construction projects may not be completed within forecasted budget, schedule or scope parameters or could be canceled which could adversely affect our business and results of operations.
Our Energize365 business plan calls for extensive capital investments totaling approximately $28 billion from 2025 through 2029, including but not limited to our transmission expansion program and our distribution grid modernization, resiliency and reliability programs. We may be exposed to the risk of substantial price increases in, or the adequacy or availability of, the costs of labor and materials used in construction, nonperformance of equipment and increased costs due to inflation, interest rates or other macroeconomic forces, delays, including delays relating to the procurement of permits or approvals, adverse weather or environmental matters. We engage numerous contractors and enter into a large number of construction agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. Also, because we enter into construction agreements for the necessary materials and to obtain the required construction related services, any cancellation by FirstEnergy of a construction agreement could result in significant termination payments or penalties. Any delays, increased costs or losses, or cancellation of a construction project could adversely affect our business and results of operations, particularly if we are not permitted to recover any such costs in rates.
Physical acts of war, terrorism, sabotage or other attacks on any of our facilities or other infrastructure could have an adverse effect on our business, results of operations, cash flows and financial condition.
As a result of the continued threat of physical acts of war, terrorism, sabotage or other attacks in the United States, our electric generation, fuel storage, transmission and distribution facilities and other infrastructure, including power plants, transformer and high voltage lines and substations, or the facilities or other infrastructure of an interconnected company, could be direct targets of, or indirect casualties of, an act of war, terrorism, sabotage or other attack, which could result in disruption of our ability to generate, purchase, transmit or distribute electricity for a significant period of time, otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such disruption or incident could result in a significant decrease in revenue, significant additional capital and operating costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our assets over and above any available insurance reimbursement, higher insurance deductibles, higher premiums and more restrictive insurance policies, legal claims or proceedings, greater regulation with higher attendant costs, generally, and significant damage to our reputation, which could have a material adverse effect on our business, results of operations, cash flows and financial condition.
Failure to provide safe and reliable service and equipment could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results.
We are committed to providing safe and reliable service and equipment in our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. However, our employees, contractors and the general public may be exposed to dangerous environments due to the nature of our operations. Failure to provide safe and reliable service and equipment due to various factors, including cyber or physical attacks, equipment failure, accidents, human error, weather or natural disasters, could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results through reduced revenues, increased capital and operating costs, litigation or the imposition of penalties/fines or other adverse regulatory outcomes.
The outcome of litigation, arbitration, mediation, and similar proceedings involving our business, or that of one or more of our operating subsidiaries, is unpredictable. An adverse decision in any material proceeding could have a material adverse effect on our financial condition and results of operations.
We are involved in a number of litigation, arbitration, mediation, and similar proceedings, including with respect to asbestos claims. These and other matters may divert financial and management resources that would otherwise be used to benefit our operations. Further, no assurances can be given that the resolution of these matters will be favorable to us. If certain matters were ultimately resolved unfavorably to us, our results of operations and financial condition could be materially adversely impacted. See Note 15. “Commitments, Guaranties and Contingencies” of the Notes to Consolidated Financial Statements for a summary of such matters.
In addition, we are sometimes subject to investigations and inquiries by various state and federal regulators due to the heavily regulated nature of our industry. Any material inquiry or investigation could potentially result in an adverse ruling against us, which could have a material adverse impact on our financial condition and operating results.
We face certain human resource risks associated with potential labor disruptions and/or with the availability of trained and qualified labor to meet our future staffing requirements.
We are continually challenged to find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. Our costs, including costs for contractors to replace employees and productivity costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully recruit and retain an appropriately qualified workforce, our results of operations could be negatively affected.
Additionally, a significant number of our physical workforce are represented by unions. While we believe that our relations with our employees are generally fair, we cannot provide assurances that the company will be completely free of labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, lockouts or that any labor disruption will be favorably resolved. Mitigating these risks could require additional financial commitments and the failure to prevent labor disruptions and retain and/or attract trained and qualified labor could have an adverse effect on our business.
Significant increases in our operation and maintenance expenses, including our health care and pension costs, could adversely affect our future earnings and liquidity.
We continually focus on limiting and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures related to operation and maintenance expenses, including in the areas of health care and pension costs. We have experienced health care cost inflation in recent years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, discount rates, health care cost trends, benefit design
changes, salary increases, the demographics of plan participants and regulatory requirements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates-Pension and OPEB Accounting.” While we anticipate that our operation and maintenance expenses will continue to increase, if actual results differ materially from our assumptions, our costs could be significantly higher than expected which could adversely affect our results of operations, financial condition and liquidity.
Advances in and widespread adoption of distributed generation and regulatory policies may make our facilities significantly less competitive and adversely affect our results of operations.
Traditionally, electricity is generated at large, central station generation facilities distributed by our systems. This method results in economies of scale and lower unit costs than newer generation technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in newer generation technologies will make newer generation technologies more cost-effective, or that legislation addressing climate change at the federal or state level together with changes in regulatory policy will create incentives or benefits that otherwise make these newer generation technologies even more competitive with central station electricity production. To the extent that newer generation technologies are connected directly to load, bypassing the transmission and distribution systems, potential impacts could include decreased transmission and distribution revenues, stranded assets and increased uncertainty in load forecasting and integrated resource planning and could adversely affect our business and results of operations.
Energy companies are subject to adverse publicity that makes them vulnerable to negative regulatory and legislative outcomes, which could have an adverse impact on our business.
Energy companies, including the Electric Companies and Transmission Companies, have been the subject of criticism on matters including the reliability of their distribution or transmission services and systems and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, as well as negative publicity associated with the operation of coal-fired generation or proceedings seeking regulatory recoveries may cause less favorable legislative and regulatory outcomes and damage our reputation, which could have an adverse impact on our business and financial condition.
Our results of operations could be adversely affected by events beyond our control, such as natural disasters, public health crises, government shutdowns, trade wars, recessions, political crises, negative global climate patterns, mine subsidence, or other catastrophic events.
Our operations, or those of our vendors or suppliers, could be negatively impacted by various events beyond our control, including, but not limited to: natural disasters, such as hurricanes, tornadoes, floods, earthquakes, wildfires, extreme cold weather events and other adverse weather conditions; public health crises, such as pandemics and epidemics; prolonged government or regulator furloughs or shutdowns; trade wars; recessions; political crises, such as terrorist attacks, war, labor unrest, and other political instability; negative global climate patterns, especially in water stressed regions; surface subsidence from underground mining impacting our facilities; or other catastrophic events, such as fires or other disasters occurring at our distribution facilities or our service providers’ facilities, whether occurring in the United States or internationally. These events could disrupt the operations of our corporate offices and our supply chain and those of our vendors and service providers, as well as disrupting our infrastructure and that of third parties with whom we are connected. To the extent any of these events occur, our operations and financial results could be adversely affected.
Risks Associated with Climate Change, GHG Emissions and Other Environmental Matters
Our aspirations and disclosures related to climate matters expose us to risks that could adversely affect our reputation and performance.
We have published statements concerning our climate-related goals and aspirations. We are targeting Scope 1 carbon neutrality by 2050, which for us includes emissions, sulfur hexafluoride leaks from transmission and distribution equipment, and our mobile fleet (i.e., vehicles). These statements reflect our aspirations and are not guarantees that we will be able to achieve them. Our failure to adequately update, accomplish or accurately track and report on these goals on a timely basis, or at all, could adversely affect our reputation, financial performance and growth, and expose us to increased scrutiny from the investment community, special interest groups and enforcement authorities, including at the state and local levels. Conversely, certain “anti-environmental, social and governance” sentiment among some individuals and government institutions pose the risk that we may face increasing scrutiny, reputational risk, or lawsuits from these parties.
Our ability to achieve our GHG reduction objective is subject to our ability to make operational changes and is conditioned upon numerous risks, many of which are outside of our control. Examples of such risks include the evolving regulatory requirements in the jurisdictions in which we operate, including the interpretation of such regulations, potential changes to such laws and regulations as a result of the new U.S. presidential administration, the prevalence of certain standards or disclosures, the evolving laws applicable to climate-related and other environmental matters, and the availability of funds to invest in initiatives in times where we are seeking to reduce costs.
Standards for tracking and reporting of climate and other environmental matters continue to evolve. Our selection of voluntary disclosure frameworks and standards, and the interpretation or application of those frameworks and standards, may change from time to time or differ from those of others. Methodologies for reporting this data may be updated and previously reported data may be adjusted to reflect improvement in availability and quality of third-party data, changing assumptions, changes in the nature and scope of our operations and other changes in circumstances. Our processes and controls for reporting these matters across our operations and supply chain are evolving along with multiple disparate standards for identifying, measuring, and reporting these metrics, including climate-related disclosures that are or may be required by the SEC, state legislatures, or other regulators, and such standards may change over time, which could result in significant revisions to our current goals, reported progress in achieving such goals, or ability to achieve such goals in the future. If our practices do not meet evolving investor or other stakeholder expectations and standards, then our reputation or our attractiveness as an investment, business partner, acquiror, service provider or employer could be negatively impacted.
We have coal-fired generation capacity, which exposes us to risk from regulations relating to coal, GHGs and CCRs, which could lead to increased costs or the need to spend significant resources to defend allegations of violation.
We own and maintain coal-fired generating plants located in West Virginia. Historically, coal-fired generation has greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to air emissions, including GHGs and CCR disposal, than other types of electric generation facilities. To the extent that changes in government policies limit or restrict the usage of coal as a source of fuel in generating electricity or alternate fuels, such as natural gas, or displace coal on a competitive basis, our business and results of operations could be adversely affected. These legal requirements and any future initiatives could impose substantial additional costs and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities and could require our coal-fired generation to curtail generation or cease to generate. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
We are or may be subject to environmental liabilities, including costs of remediation of environmental contamination at current or formerly owned facilities, which could have a material adverse effect on our results of operations and financial condition.
We may be subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned or operated by us and of property contaminated by hazardous substances regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We are currently involved in a number of proceedings relating to sites where hazardous substances have been released and we may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former MGP operations are one source of such costs, as are legacy CCR surface impoundments. See Note 15, "Commitments, Guarantees and Contingencies" of the Notes to Consolidated Financial Statements. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material. In addition, there can be no assurance that any liabilities, losses or expenditures we may incur related to such environmental liabilities or contamination will be covered under any applicable insurance policies or that the amount of insurance will be adequate.
In some cases, a third party who has acquired assets including operating and deactivated nuclear power stations from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses.
Federal and various regional and state authorities regulate GHG emissions, including CO2 emissions and have created financial incentives to reduce them. In 2023, FirstEnergy operated businesses that had total Scope 1 CO2 emissions of approximately 15.2 million metric tons. For existing power generation plants, CO2 emissions data are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. This estimate is based on a number of projections and assumptions that may prove to be incorrect, such as the forecasted dispatch, anticipated plant efficiency, fuel type, CO2 emissions rates and our subsidiaries’ achieving completion of such construction and development projects. While actual emissions may vary substantially, the projects under construction or development when completed will increase emissions of our portfolio and therefore could increase the risks associated with regulation of GHG emissions, and although the new U.S. presidential administration issued an executive order in January 2025 withdrawing the United States from the United Nations Framework Convention on Climate Change’s Paris Agreement (“Paris Agreement”), future presidential administrations with differing energy and climate priorities could take actions that result in new or additional GHG emissions regulations in the future.
In 2010, the EPA adopted regulations pertaining to GHG emissions that require new and existing sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or modification. In 2016, the U.S. Supreme Court ruled that such permitting would only be required if such sources also must obtain a new source review permit for increases in other regulated pollutants. In addition, the EPA previously announced plans to implement new climate change programs, including regulation of greenhouse gas emission from the utility industry. For further discussion of the regulation of GHG emissions, see Item 1.-Business-Environmental Matters - Climate Change, above. The Paris Agreement established a long-term goal of keeping the increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to decarbonize the global economy and to further limit GHG emissions.
Furthermore, the SEC has finalized climate-related disclosure rules, and although these SEC climate-related disclosure rules have been stayed, certain states have begun to pass their own laws related to GHG emissions. The impact of GHG regulation on our operations will depend on a number of factors, including the degree and timing of GHG emissions reductions required under any such legislation or regulation, the cost of emissions reduction equipment and the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred through rate increases or otherwise. The costs of compliance could be substantial.
We have a minority ownership stake in a coal mine that requires governmental permits and approvals to operate, and a failure of the coal mine to renew and maintain such permits and approvals may adversely affect our results of operations and cash flow.
FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales predominantly in international markets. The viability of our investment depends upon several factors beyond our control, including, but not limited to: Signal Peak’s ability to renew and maintain governmental permits and approvals and remain in compliance with federal, state, and local safety and environmental statutes, rules, and regulations affecting the coal mining industry. Failure by Signal Peak to renew and maintain necessary permits and approvals, and to comply with any such statutes, rules and regulations, may impair its operations and the ability to generate cash flows necessary for Global Holding to pay future dividends and contribute to FirstEnergy’s earnings.
Signal Peak operates a single underground coal mine in south-central Montana and must obtain numerous governmental permits and approvals that impose strict conditions and obligations relating to, among other things, various environmental and safety matters in connection with its mining and coal transportation operations. The rules applicable to these permits and approvals are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. In addition, the public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Limitations on Signal Peak’s ability to conduct its mining operations due to its inability to obtain or renew necessary permits or similar approvals could materially reduce or even halt production at the mine resulting in an adverse effect on our balance sheet, results of operations and cash flow.
Costs of compliance with environmental laws are significant, and the cost of compliance with new environmental laws, including limitations on GHG emissions related to climate change, could adversely affect our cash flows and financial condition.
Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations, which are continuously evolving. Compliance with these legal requirements requires us to incur costs for, among other things, installation and operation of pollution control equipment, emissions monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. We may be forced to shut down other facilities or change their operating status, either temporarily or permanently, if we are unable to comply with these or other existing or new environmental requirements, or if the expenditures required to comply with such requirements are unreasonable.
Moreover, new federal, state or local environmental laws or regulations including, but not limited to GHG emissions, Clean Water Act effluent limitations imposing more stringent water discharge regulations, or other changes to existing environmental laws or regulations, or the interpretation of such regulations, may materially increase our costs of compliance or accelerate the timing of capital expenditures or other capital-like investments. Our compliance strategy, including but not limited to, our assumptions regarding estimated compliance costs, although reasonably based on available information, may not successfully address future relevant standards and interpretations, including with respect to evolving federal policies that may be adopted by the new U.S. presidential administration or new regulations adopted by the states in which we operate. If we fail to comply with environmental laws and regulations or new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations. Due to the uncertainty of control technologies available to reduce GHG emissions, any legal obligation that requires substantial reductions of GHG emissions could result in substantial additional costs, adversely affecting cash flows and profitability, and raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.
The EPA may conduct NSR investigations at our generating plants, which could result in the imposition of fines.
We may be subject to risks from changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of the EPA's NSR programs. Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing generation facilities to the far more stringent new source standards applicable to new generation facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards during work considered by the companies to be routine maintenance. The EPA has previously investigated alleged violations of the NSR standards at certain of our existing and former generating facilities. Should the EPA investigate our generating plants in the future, it could, if violations were discovered, result in the imposition of fines.
We could be exposed to private rights of action relating to environmental matters seeking damages under various state and federal law theories which could have an adverse impact on our results of operations, financial condition, cash flows and business operations.
Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other relief. For example, claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in other actions making similar allegations. An unfavorable ruling in any such case could result in the need to make modifications to our coal-fired generation or reduce emissions, suspend operations or pay money damages or penalties. Adverse rulings in these or other types of actions could have an adverse impact on our results of operations, cash flows and financial condition and could significantly impact our business operations.
Transition risks associated with climate change, including those related to regulatory mandates could negatively impact our financial results.
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce peak demand and energy consumption. Such conservation programs have previously resulted in and could result in further load reduction and adversely impact our financial results in different ways. We currently have energy efficiency riders in place in certain of our states to recover the cost of these programs either at or near a current recovery time frame in the states where we operate.
In our regulated operations, energy conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. In the past, we have been adversely impacted by reduced electric usage due in part to energy conservation efforts such as the use of efficient lighting products such as compact fluorescent lights, halogens and light emitting diodes. We are unable to determine what impact, if any, future conservation activities will have on our financial condition or results of operations.
Additionally, failure to meet regulatory or legislative requirements to reduce energy consumption or otherwise increase energy efficiency could result in penalties that could adversely affect our financial results.
Financial and reputational risks associated with owning coal-fired generation and a minority-interest in a coal mine may have an adverse impact on our business operations, financial condition and cash flows.
MP's fleet consists of 3,093 MWs of coal-fired generation and FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with international coal sales. Certain members of the investment community have adopted investment policies promoting the divestment of, or otherwise limiting new investments in, coal-fired generation and coal mining. The impact of such efforts may adversely affect the demand for and price of our common stock and impact our and MP's access to the capital and financial markets. Further, certain insurance companies have established policies limiting coal-related underwriting and investment. Consequently, these policies aimed at coal-fired generation could have a material adverse impact on our reputation, business operations, financial condition, and cash flows.
The Physical Risks Associated with Climate Change May Have an Adverse Impact on Our Business Operations, Financial Condition and Cash Flows.
Physical risks of climate change, such as flooding, wildfires, rising sea levels, and other related phenomena, resulting from more frequent or more extreme weather events and changes in temperature and precipitation patterns associated with climate change, could affect some, or all, of our operations. Frequent or extreme weather events could disrupt our operations and/or be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Electric Companies' and Transmission Companies’ service areas could also directly affect their capital assets, such as downed wires, poles, or damage to other operating equipment, resulting in service disruptions to customers and possibly creating hazardous conditions. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions and, in some instances, we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our business operations, financial condition and cash flows.
Climate change poses other financial risks as well. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased revenues, margins or earnings.
Risks Associated with Markets and Financial Matters
Our results of operations and financial condition may be adversely affected by the volatility in pension and OPEB investments and obligations due to capital market performance and other changes.
FirstEnergy recognizes in income the change in the fair value of plan assets and net actuarial gains and losses for its pension and OPEB plans. This adjustment to income associated with the change in fair value is recognized in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, which could result in greater volatility in pension and OPEB expenses and may materially impact our results of operations.
Our financial statements reflect the values of the assets held in trust to satisfy our obligations under pension and OPEB plans. Certain of the plan assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to pay future pension and other obligations requires significant judgment and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or that negatively impact the discount rate and increase the present value of liabilities may increase our future pension and OPEB expenses and further may have significant impacts on the value of the pension and other trust funds, which could require significant additional funding and negatively impact our results of operations and financial position. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates-Pension and OPEB Accounting.”
Our results of operations and financial condition may be adversely affected by certain risks related to our minority interest in a coal mine.
FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales predominantly in international markets. In the second quarter of 2022, FEV received its first dividend of $20 million after more than ten years of equity ownership in the joint venture and received total dividends in 2022, 2023, and 2024 of $170 million, $165 million, and $80 million, respectively. Additionally, during 2022, 2023, and 2024, FirstEnergy recognized approximately $168 million, $175 million, and $72 million of pre-tax equity earnings, excluding impairments, respectively, from its investment in Global Holding. Global Holding’s ability to positively affect our results of operations or pay future dividends depends upon several factors beyond our control, including, but not limited to: the market price of coal, the availability and reliability of transportation facilities and other systems, geopolitical stability in international markets, and Global Holding’s ability to renew and maintain governmental permits and approvals and remain in compliance with safety and environmental regulations affecting the coal mining industry.
The price for Signal Peak’s coal depends upon factors beyond our control, including but not limited to: overall global economic and geopolitical conditions, the effect of worldwide energy consumption, including the impact of technological advances on energy consumption; international developments impacting the supply of coal; international developments impacting the supply of oil & gas; and the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations. Any adverse change in these factors could result in weaker demand and lower prices for Global Holding’s products, and, as a result, could impact Global Holding’s ability to pay future dividends, which in turn could adversely affect our cash flow and results of operations.
Failure to comply with debt covenants in our credit agreements or conditions could adversely affect our ability to execute future borrowings and/or require early repayment, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all.
Our debt and credit agreements contain various financial and other covenants including a requirement for FE to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters, and that each other borrower maintain a consolidated debt-to-total-capitalization ratio of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. As of December 31, 2024, FE was in compliance with its applicable consolidated interest coverage ratio and the borrowers in each case as defined under the 2021 Credit Facilities and 2023 Credit Facilities, were in compliance with their debt-to-total-capitalization ratio covenants.
Our credit agreements contain certain negative and affirmative covenants. Our ability to comply with the covenants and restrictions contained in the 2021 Credit Facilities and 2023 Credit Facilities has been and may, in the future, be affected by events related to the ongoing government investigations or otherwise, including a failure to comply with the terms of the DPA.
A breach of any of the covenants contained in our credit agreements, including any breach related to alleged failures to comply with anti-corruption and anti-bribery laws, could result in an event of default under such agreements, and we would not be able to
access our credit facilities for additional borrowings and letters of credit while any default exists. Upon the occurrence of such an event of default, any amounts outstanding under our credit facilities could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our credit facilities is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. In addition, certain events, including but not limited to any covenant breach related to alleged failures to comply with anti-corruption and anti-bribery laws, an event of default under our credit agreements, and the acceleration of applicable commitments under such facilities could restrict our ability to obtain additional or replacement financing on acceptable terms or at all. The operating and financial restrictions and covenants in our credit facilities and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities which in turn could have a material adverse impact on our business, cash flow, liquidity and results of operations.
A credit rating downgrade could negatively affect our or our subsidiaries’ financing costs, ability to access capital and requirement to post collateral.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. Certain of FirstEnergy’s subsidiaries have in the past been subject to downgrade of credit ratings. Any future downgrades in FirstEnergy or FirstEnergy subsidiaries' credit ratings from the nationally recognized credit rating agencies, particularly to levels below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, additional downgrades could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. Additional rating downgrades would further increase our interest expense on certain of FirstEnergy's long-term debt obligations and would also further increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. Such additional rating downgrades could also negatively impact our ability to grow our regulated businesses or execute our business strategies by substantially increasing the cost of, or limiting access to, capital.
In addition, events related to the ongoing government investigations may expose us to higher interest rates for additional indebtedness, whether as a result of ratings downgrades or otherwise, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all. See “Failure to comply with debt covenants in our credit agreements or conditions could adversely affect our ability to execute future borrowings and/or require early repayment, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all.”
In the event of volatility or unfavorable conditions in the capital and credit markets, our business, including the immediate availability and cost of short-term funds for liquidity requirements, our ability to meet long-term commitments and the competitiveness and liquidity of energy markets may be adversely affected, which could negatively impact our results of operations, cash flows and financial condition.
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use LOCs provided by various financial institutions to support our hedging operations. We also deposit cash in short-term investments. In the event of volatility in the capital and credit markets, our ability to access the capital markets or draw on our credit facilities and cash may be adversely affected. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
Should there be fluctuations in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant foreign or domestic financial institutions or foreign governments, our access to liquidity needed for our business could be adversely affected. Unfavorable conditions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other capital-like investments, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash. Energy markets depend heavily on active participation by multiple counterparties, which could be adversely affected should there be disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
The IRA of 2022 could change the rate of taxes imposed on us and could negatively affect our cash flows and financial condition.
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 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. 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.
Changes in local, state or federal tax laws applicable to us or adverse audit results or tax rulings, and any resulting increases in taxes and fees, may adversely affect our results of operations, financial condition and cash flows.
FirstEnergy is subject to various local, state and federal taxes, including income, franchise, real estate, sales and use and employment-related taxes. We exercise significant judgment in calculating such tax obligations, booking reserves as necessary to reflect potential adverse outcomes regarding tax positions we have taken and utilizing tax benefits, such as carryforwards and credits. Additionally, various tax rate and fee increases may be proposed or considered in connection with such changes in local, state or federal tax law. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by legislatures or regulatory bodies. Any such changes, or any adverse tax audit results or adverse tax rulings on positions taken by FirstEnergy or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.
We cannot predict whether, when or to what extent new U.S. tax laws, regulations, interpretations or rulings will be issued. A reform of U.S. tax laws may be enacted in a manner that negatively impacts our cash flow, results of operations, and financial condition.
We are a holding company and rely on cash from our subsidiaries to meet our financial obligations and therefore any restrictions on the Electric Utilities and Transmission Companies’ ability to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.
Because FE is a holding company with no operations or cash flows of its own, our ability to meet our financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on our common stock, is primarily dependent on the net income and cash flows of our subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding FE, our subsidiaries have regulatory restrictions and financial obligations that must be satisfied.
For example, the Electric Companies and Transmission Companies are regulated by various state utility and federal commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state and federal commissions could attempt to impose restrictions on the ability of the Electric Companies and Transmission Companies to pay dividends or otherwise restrict cash payments to us. Any inability of our subsidiaries to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.
We may also provide capital contributions or debt financing to our subsidiaries under certain circumstances, which would reduce the funds available to meet financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on our common stock.
We cannot assure common shareholders that future dividend payments will be made, or if made, in what amounts they may be paid.
The FE Board will continue to regularly evaluate our common stock dividend and determine whether to declare a dividend, and an appropriate amount thereof, each quarter taking into account such factors as, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
The first mortgage indentures for the Ohio Companies, FE PA, MP and PE constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. The outstanding debt under the FMBs of specific FE PA predecessors (WP and Penn) were assumed by FE PA in connection with the PA Consolidation. See Note 12, "Capitalization," of the Notes to Consolidated Financial Statements for information concerning financing encumbrances affecting certain of the Electric Companies' properties.
FirstEnergy controls the following generation sources as of December 31, 2024, shown in the table below, and operates in the PJM Region. Except for the OVEC participation referenced in the footnotes to the table, the Integrated segment generating units are owned by MP.
Plant (Location) Unit Total Corporate / Other Integrated Total Corporate / Other Integrated
Net Maximum Capacity (MW) Net Generation for the year ended December 31, 2024(3)
(Thousand MWh)
Coal-fired:
Harrison Power Station (Haywood, WV) 1-3 1,984 - 1,984 10,618 - 10,618
Fort Martin Power Station (Maidsville, WV) 1-2 1,098 - 1,098 3,860 - 3,860
OVEC (Cheshire, OH) (Madison, IN)(1)
1-11 78 67 11 350 301 49
3,160 67 3,093 14,828 301 14,527
Pumped-storage Hydro:
Bath County Pumped Storage Station (Warm Springs, VA)(2)
1-6 487 - 487 990 - 990
Solar
Fort Martin Solar (Maidsville, WV) 19 - 19 28 - 28
Rivesville Solar (Rivesville, WV) 5 - 5 2 - 2
24 - 24 30 - 30
Total 3,671 67 3,604 15,848 301 15,547
(1) Represents AE Supply's 3.01% and MP's 0.49% entitlement based on their participation in OVEC.
(2) Represents AGC's 16.25% undivided interest in Bath County. The station is operated by VEPCO.
(3) Each plant is net of station use, except for Bath County, which is shown gross of pumping usage.
MP and PE are constructing 50 MWs of solar generation at five sites in West Virginia. The WVPSC approved the construction of three of the five solar sites. The first solar generation site, Fort Martin Solar, located in Maidsville, West Virginia, was completed and placed in-service on January 8, 2024, representing 19 MWs of capacity. The second solar generation site, Rivesville Solar, located in Rivesville, West Virginia, went into service on September 25, 2024. Construction of the remaining three sites, once completed, are expected to provide 26 MWs of additional net maximum generation capacity.
As of December 31, 2024, FirstEnergy’s distribution and transmission circuit miles are located in PJM and were as follows:
Distribution
Line Miles(1)
Transmission
Line Miles
ATSI - 7,964
CEI 31,855 -
FE PA(2)(3)
82,467 2,623
JCP&L 24,781 2,609
KATCo(3)
- 1,696
MAIT - 4,287
MP 23,036 2,607
OE 54,760 -
PE 20,253 2,088
TE 15,092 -
TrAIL - 269
Total 252,244 24,143
(1) Includes overhead pole line and underground conduit carrying primary, secondary and street lighting circuits.
(2) On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, making it a new, single operating entity.
(3) On January 1, 2024, WP's Pennsylvania-based transmission assets of 115 kV and above were transferred to KATCo, while the remaining transmission assets below 115 kV continue to be held by FE PA.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 14, "Regulatory Matters," and Note 15, "Commitments, Guarantees and Contingencies," of the Notes to Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
HOLDERS OF COMMON STOCK
There were 53,295 holders of 576,612,245 shares of FE’s common stock as of December 31, 2024, and 52,730 holders of 576,697,425 shares of FE's common stock as of January 31, 2025. FE has historically paid quarterly cash dividends on its common stock. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions. Information regarding equity available for payment of cash dividends is given in Note 12, "Capitalization," of the Notes to Consolidated Financial Statements.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2019, in FE’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
FirstEnergy had no transactions regarding purchases of FE common stock during the fourth quarter of 2024.
FirstEnergy does not have any publicly announced plan or program for share purchases.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements: This Form 10-K includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms):
•The potential liabilities, increased costs and unanticipated developments resulting from government investigations and agreements, including those associated with compliance with or failure to comply with the DPA, and settlements with the OAG's office and 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 those vendors with which we do business.
•Variations in weather, such as mild seasonal weather variations and severe weather conditions (including events caused, or exacerbated, by climate change, such as wildfires, hurricanes, flooding, droughts, high wind events and extreme heat events) and other natural disasters, which may result in increased storm restoration expenses 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 risks associated with physical attacks, such as acts of war, terrorism, sabotage or other acts of violence, and cyber-attacks and other disruptions to our, or our vendors’, information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information.
•The ability to meet our goals relating to climate-related and environmental, social and governance matters, opportunities, improvements, and efficiencies, including our GHG reduction goals.
•The ability to accomplish or realize anticipated benefits through establishing a culture of continuous improvement and our other strategic and financial goals, including, but not limited to, 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 us to make contributions to our pension sooner or in amounts that are larger than currently anticipated.
•Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets, including those sites impacted by the legacy CCR rules that were finalized during 2024.
•Changes to environmental laws and regulations, including, but not limited to, rules finalized by the EPA and SEC, including those currently stayed, related to climate change, and potential changes to such laws and regulations as a result of the new 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.
•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 our status as a well-known seasoned issuer.
•Future actions taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity.
•Changes in assumptions regarding factors such as economic conditions within our territories, the reliability of our transmission and distribution system, generation resource planning, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities.
•The potential of non-compliance with debt covenants in our credit facilities.
•The ability to comply with applicable reliability standards and energy efficiency and peak demand reduction mandates.
•Human capital management challenges, including among other things, attracting and retaining appropriately trained and qualified employees and labor disruptions by our unionized workforce.
•Changes to significant accounting policies.
•Any changes in tax laws or regulations, including, but not limited to, the IRA of 2022, or adverse tax audit results or rulings and potential changes to such laws and regulations as a result of the new U.S. presidential administration.
•The risks and other factors discussed from time to time in our SEC filings.
Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by the FE Board at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
These forward-looking statements are also qualified by, and should be read together with, the risk factors included in (a) Item 1A. Risk Factors, (b) Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in FirstEnergy's other filings with the SEC. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. We expressly disclaim any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference as a result of new information, future events or otherwise.
Forward-looking and other statements in this Annual Report on Form 10-K regarding our Climate Strategy, including our GHG emission reduction goals, are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding climate matters, including GHG emissions, may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.
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 December 31, 2024, AGC and MP control 3,604 MWs of net maximum generation capacity.
Segment Overview
During the first quarter of 2024, FirstEnergy’s segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. FirstEnergy’s reportable segments are as follows:
The Distribution segment, which consists of the Ohio Companies and FE PA, representing $11 billion in rate base as of December 31, 2024, 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, representing $9.6 billion in rate base as of December 31, 2024. 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 January and September 2024, representing 24 MWs of net maximum generating capacity. The remaining three sites, once completed, are expected to provide 26 MWs of additional net maximum generation capacity.
The Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, representing $5.3 billion in rate base as of December 31, 2024, includes transmission infrastructure owned and operated by the Transmission Companies and used to transmit electricity. The segment’s revenues are primarily derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains in the Stand-Alone Transmission segment. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and prior year results in the Stand-Alone Transmission segment reflect the earnings and results of those WP transmission assets.
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. 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 December 31, 2024, Corporate/Other had approximately $6.1 billion of external FE holding company debt.
FirstEnergy believes that this segment reporting serves to provide:
•Greater transparency into our business unit performance;
•Alignment with our cash flow, credit metrics, balance sheet and earnings to the companies comprising each segment;
•Simplification of our segment reporting so that each entire entity resides within a segment; and
•Consistency with peers.
PA Consolidation
On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.
Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.
FET Equity Interest Sale
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes. Interest income associated with the promissory notes was $24 million for the year ended December 31, 2024 and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.
Asset Retirement Obligations
On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments, 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. In anticipation of such expenditures, FirstEnergy performed a preliminary assessment of former CCR disposal sites and calculated an initial estimate applying historical experience in remediating comparable sites. As a result, FirstEnergy recorded a $139 million increase to its ARO during 2024, of which $113 million is included in “Other operating expenses” on the Consolidated Statements of Income and was not capitalized as an asset retirement cost since the associated plants do not have future cash flows.
On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of December 31, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. During the second quarter of 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 and corresponding increase to “Other operating expense” of $87 million at Corporate/Other for segment reporting. On February 3, 2025, AE Supply executed an environmental liability transfer agreement with a subsidiary of IDA Power, LLC, whereby AE Supply will transfer the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations. The agreement requires AE Supply to establish a $160 million escrow account that AE Supply will fund over five years. The escrow funding obligation will be secured by a surety bond, which will be guaranteed by FE. The transaction is expected to close before the end of the first quarter of 2025 and the derecognition of the ARO is not expected to have a material impact to FirstEnergy’s financial statements, however, no assurances of the closing of the transfer will be satisfied, including transfer of all required environmental permits. See Note 10, “Asset Retirement Obligations,” of the Notes to Consolidated Financial Statements.
Our Strategy
Powered by its employees and guided by its experienced leadership team and engaged FE Board, FirstEnergy is accelerating its transformation into a premier electric company. The FE Board and FirstEnergy’s executive management team are aligned behind a business model grounded in investing, operating, recovering costs and financing our regulated electric company operations. This business model aims to create a “virtuous cycle” that, in turn, serves to improve reliability and the customer experience, grow rate base, engage employees, improve returns and maintain a strong balance sheet. Along with an unwavering commitment to ethics and integrity, performance excellence and continuous improvement, FirstEnergy anticipates that strong execution of this model will help achieve its strategic objectives and deliver value to its investors.
With a diversified asset mix, improved balance sheet and a strong affordability position, FirstEnergy is well positioned to significantly enhance the customer experience and provide value to its investors.
Invest
FirstEnergy invests in its regulated operations to improve reliability and the customer experience, and in its people to attract, retain and develop talented, diverse and engaged employees to carry out its strategy. This includes the following:
•A robust plan for customer-focused growth, Energize365 is the centerpiece of FirstEnergy’s regulated distribution and transmission capital investment strategy that aims to strengthen the grid and enable the energy transition. Through the Energize365 program, FirstEnergy invested $4.5 billion in 2024, approximately 20% higher than 2023, and expects to spend approximately $28 billion in system-wide capital investments from 2025 through 2029. FirstEnergy expects that these investments will comprise the Distribution segment (26%), the Integrated segment (39%), and the Stand-Alone Transmission segment (34%), focusing on the following:
•Distribution and Transmission investments to support improvements in grid reliability and resiliency and support the energy transition, including through:
◦Programs to drive system resiliency through automation technology and communication, including phases one and two of the Ohio Companies’ distribution grid modernization plans, Pennsylvania's LTIIP, New Jersey's EnergizeNJ, and implementing advanced metering infrastructure;
◦Operational flexibility projects that are expected to build capacity and support the evolving grid such as interconnection of New Jersey offshore wind and data center load;
◦Enhancing system performance by implementing new designs and technologies to reduce load at risk; and
◦Upgrading system conditions that enhance reliability.
•West Virginia solar generation projects, energy efficiency initiatives, electric vehicle infrastructure and energy storage projects.
•Base distribution projects to address aging infrastructure.
•Generation maintenance projects that maintain operations of fossil fuel plants and remain compliant with environmental regulations through the end of their useful life.
•FirstEnergy believes there is a continued long-term pipeline of investment opportunities for its existing distribution and transmission infrastructure beyond those opportunities identified through 2029, which are expected to strengthen grid
and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.
•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., as 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.
•A refreshed and revitalized leadership team. During 2024, FirstEnergy appointed five executives to oversee the Maryland/West Virginia, Ohio, Pennsylvania, New Jersey and Transmission operations. Additionally, FirstEnergy also announced the hiring of five vice presidents that will be responsible for developing and implementing the financial strategy and oversee relationships with regulators for Pennsylvania, New Jersey, West Virginia, Maryland, Ohio and Transmission.
Operate
FirstEnergy will continue to engage its skilled, trained, talented and diverse team of employees to effectively implement its investment plans, seek opportunities for continuous improvement as it delivers safe, reliable and affordable electricity to our customers, and deliver value to its investors. It aims to do so through the following:
•Enhancing the focus on the customer. FirstEnergy has shifted more decision-making and accountability for our operations closer to our customers, regulators and employees doing the work. FirstEnergy’s new operating structure is organized as follows: Ohio, Pennsylvania, New Jersey, West Virginia/Maryland and FirstEnergy’s Standalone Transmission properties. This structure fosters better execution at the business unit level.
•Embracing a continuous improvement mindset. FirstEnergy is focused on operational excellence through strong execution of our capital investments to enhance the customer experience and support the energy transition, managing costs and keeping customer bills affordable and reducing regulatory lag.
Recover
FirstEnergy is establishing a track record of strong execution. Operating effectively leads to strong, predictable results and enhances credibility with our stakeholders. In turn, FirstEnergy builds supportive relationships with regulators, customers and intervenors in an effort to drive positive rate outcomes that support recovery of its investments.
In order to achieve important regulatory milestones, FirstEnergy has an active regulatory calendar to support its regulated growth strategy and address the critical investments that support reliability and a smarter electric grid. This includes the following:
New Jersey
•On March 16, 2023, JCP&L filed a base rate case in New Jersey, requesting a $185 million increase in base distribution revenues to support investments to strengthen the energy grid, enhance the customer experience and provide assistance to low-income and senior citizen customers. On February 1, 2024, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s request for a distribution base rate increase. The settlement, which was approved by the NJBPU on February 14, 2024, provides for an $85 million annual base distribution revenue increase for JCP&L, which became effective for customers on June 1, 2024.
•On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years. JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition.
•On December 1, 2023, JCP&L filed a petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and had a proposed budget of approximately $964 million. On October
30, 2024, the NJBPU approved the parties’ stipulation of settlement, wherein the parties agreed to a budget of approximately $817 million for EE&C Plan II, including $784 million of investments that will earn a return on equity of 9.6%, with an equity ratio of 52%, and will be recovered over 10 years.
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 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 has scheduled a technical conference for March 12, 2025.
•On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan, which was approved by the PUCO on December 18, 2024. The stipulation provides for the deployment of approximately 1.4 million smart meters to the balance of the Ohio Companies’ customers. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On December 18, 2024, the PUCO approved the stipulation and implementation has since begun.
•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. The Ohio Companies plan to respond and file supplemental testimony by March 24, 2025.
Pennsylvania
•On April 2, 2024, FE PA filed a base rate case with the PPUC seeking a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and which reflects a roll-in of several current riders such as DSIC, Tax Act, and smart meter. Additionally, FE PA requested an enhanced ten year vegetation management program and recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. On September 13, 2024, FE PA and the active parties to the proceeding filed a joint settlement agreement requesting that the administrative law judges
approve FE PA’s requested distribution base rate case increase subject to the terms and conditions of the settlement, which includes, among other things, an annual net revenue increase of $225 million. Other key components of the settlement agreement include recovery of costs incurred for storms and COVID-19, additional cost recovery of ongoing storm costs, inspection and maintenance of overhead lines and transformers, and rate case expenses, as well as an enhanced vegetation management program. On October 15, 2024, the administrative law judges issued a decision recommending that the PPUC approve, without modification, the September 13, 2024 settlement agreement. On November 21, 2024, the PPUC unanimously approved the settlement agreement without modification and the rates became effective on January 1, 2025.
•On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the next phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period beginning January 1, 2025 and ending December 31, 2029. FE PA’s application was approved by the PPUC on December 19, 2024, and implementation began in January 2025.
West Virginia
•On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. On August 22, 2023, the parties filed a unanimous settlement of the case recommending a $33 million annual increase in depreciation expense, effective April 1, 2024, but deferred issues related to a change in the net energy metering credit. An order was issued on March 26, 2024 approving the settlement without modification.
•On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. An agreement on the net energy metering credit was subsequently submitted to the WVPSC and was materially approved as part of the base rate case order for rates effective March 27, 2024.
Finance
We believe that FirstEnergy represents a compelling investment. With sound capital allocation targeting reliability, resiliency, the energy transition and customer experience, and supported by constructive regulatory outcomes, FirstEnergy expects to finance the business at a lower cost of capital, allowing it to begin the virtuous cycle all over again at “Invest.”
FirstEnergy aims to do this through a strengthened financial position. Since 2021, FirstEnergy has raised $7 billion in equity capital and issued $1.5 billion in convertible notes in May 2023 to significantly improve its balance sheet. The strength of FirstEnergy’s balance sheet supports its plan to fund Energize365 investments through organic internal cash flows and the issuance of debt rather than incremental equity. FirstEnergy has optimized its financing plan to retain flexibility in an uncertain interest rate environment. FirstEnergy has also taken steps to reduce potential volatility risk associated with its pension plan. In January 2025, FirstEnergy executed an additional pension lift-out transaction associated with over $652 million in pension obligations relating to its former competitive generation employees. This lift-out transaction, combined with the lift-out completed in 2023, removed approximately $1.4 billion in total pension plan assets and obligations associated with approximately 3,900 former competitive generation employees.
FirstEnergy also expects to continue returning value to shareholders. In March 2024, the FE Board declared a $0.015 per share increase to the quarterly common stock dividend payable June 1, 2024, to $0.425 per share, which represents an approximate 6% increase compared to dividends declared in 2023. Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings growth, credit metrics and other business conditions.
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 - United States 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.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve multiple shareholder derivative lawsuits that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which was granted on May 9, 2022. On August 23, 2022, the S.D. Ohio granted final approval of the settlement, which was subsequently appealed. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. All appeal options were exhausted on May 16, 2024, and the judgment and settlement became final, resolving the derivative lawsuits. On May 17, 2024, the N.D. Ohio granted the parties’ motion to dismiss based upon the approval of the settlement by the S.D. Ohio. The state court action was also dismissed on September 2, 2022.
The above settlement included a series of corporate governance enhancements and a payment to FE of $180 million, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs, and a $7 million net return on deposited funds, which was received in the second quarter of 2024. The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.
On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers relating to the conduct described in the DPA. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. FirstEnergy cooperated fully with the SEC investigation, and on September 12, 2024, the SEC issued a settlement order that concluded and resolved the investigation in its entirety. Under the terms of the settlement, FE agreed to pay a civil penalty of $100 million and to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder, which was recognized as a loss contingency of $100 million in the second quarter of 2024 at Corporate/Other for segment reporting and paid on September 25, 2024.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understood that the OOCIC’s investigation was also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. On August 12, 2024, FirstEnergy entered into a settlement with the OAG's Office, and the Summit County Prosecutor’s Office to resolve both the OOCIC investigation and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp., noted below. The settlement includes, among other things, a non-prosecution agreement and a payment of $19.5 million, which was recorded as a loss contingency in the second quarter of 2024 in FirstEnergy’s Consolidated Statements of Income at Corporate/Other for segment reporting and was paid on August 16, 2024.
Despite the many disruptions FirstEnergy has faced, and continues to currently face, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigations, the DPA, and ongoing litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FirstEnergy’s financial condition, results of operations and cash flows.
FIRSTENERGY'S CONSOLIDATED RESULTS OF OPERATIONS
2024 Compared with 2023
(In millions) For the Years Ended December 31,
2024 2023 Increase (Decrease)
Revenues $ 13,472 $ 12,870 $ 602 5 %
Operating expenses (11,097) (10,604) 493 5 %
Other expenses, net (871) (802) 69 9 %
Income taxes (377) (267) 110 41 %
Income attributable to noncontrolling interest (149) (74) 75 101 %
Earnings attributable to FE from continuing operations $ 978 $ 1,123 $ (145) (13) %
Earnings attributable to FE from continuing operations was $978 million or $1.70 per basic and diluted share in 2024 compared to $1,123 million or $1.96 per basic and diluted share in 2023, representing a decrease of $145 million that was primarily due to the following:
•A $200 million charge relating to an increase in ARO liabilities associated with final CCR rules and changes in future expected costs to remediate McElroy’s Run during 2024;
•A $100 million civil penalty resulting from the SEC investigation and a $19.5 million settlement with the OAG's office as further discussed below in “Outlook - Other Legal Proceedings”;
•A $62 million impairment charge related to the Akron general office in the third quarter of 2024;
•Lower revenues associated with changes to the Ohio DCR as a result of the PUCO’s ESP V order that became effective June 1, 2024;
•A $46 million charge for an expected refund, with interest, as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership, as further discussed below in "Outlook - Other Proceedings;"
•Higher non-deferred storm restoration expenses and planned vegetation management costs;
•Lower investment earnings related to FEV’s equity method investment in Global Holding, net of an impairment charge in the fourth quarter 2024;
•The dilutive effect of the FET Equity Interest Sale that closed in March 2024;
•Higher non-recoverable charges associated with regulatory proceedings and abandoned transmission projects;
•Higher debt redemption costs;
•Higher interest expense on long-term debt and short-term borrowings, partially offset by the redemption of certain FE long-term debt and higher capitalized financing costs; and
•A higher effective tax rate due to tax charges related to the PA Consolidation and FET Equity Interest Sale in 2024, and the absence of a reduction in state income taxes and release of a valuation allowance recognized in 2023, partially offset by discrete tax benefits in 2024 associated with certain equity method investments and the remeasurement of excess deferred income taxes.
These were partially offset by the following:
•Net proceeds from the shareholder derivative lawsuit settlement, as described below in “Outlook - Other Legal Proceedings”;
•The implementation of base rate case settlements in Maryland, New Jersey and West Virginia;
•Higher weather-related customer usage and demand;
•Increased earnings as a result of regulated investment programs that increased rate base;
•Higher interest income on the FET Equity Interest Sale promissory notes;
•Lower Pension and OPEB mark-to-market adjustment charges;
•The absence of expenses associated with the cancellation of sponsorship agreements in 2023; and
•Lower labor and benefits expenses, including those associated with the PEER program and separation-related costs.
Detailed segment reporting explanations are included below.
Distribution services by customer class are summarized in the following table:
For the Years Ended December 31,
(In thousands) Actual Weather-Adjusted
Electric Distribution MWh Deliveries(1)
2024 2023 Increase 2024 2023 Increase (Decrease)
Residential 54,631 52,217 4.6 % 55,447 55,909 (0.8) %
Commercial(2)
39,021 38,179 2.2 % 39,298 39,468 (0.4) %
Industrial 52,950 52,252 1.3 % 52,951 52,252 1.3 %
Total Electric Distribution MWh Deliveries 146,602 142,648 2.8 % 147,696 147,629 - %
(1) Reflects the reclassification of certain Pennsylvania customers from Industrial to Commercial. Due to the January 2024 consolidation of the Pennsylvania Companies, certain customers are classified as Commercial effective June 1, 2024. The MWh deliveries prior to the effective date have been adjusted for comparability.
(2) Includes street lighting.
Residential and commercial distribution deliveries were impacted by higher customer usage as a result of the weather. Cooling degree days in 2024 were 37% above 2023 and 15% above normal. Heating degree days in 2024 were 1% below 2023 and 15% below normal.
The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 16, “Segment Information,” of the Notes to Consolidated Financial Statements.
FIRSTENERGY'S CONSOLIDATED RESULTS OF OPERATIONS
2023 Compared with 2022
(In millions) For the Years Ended December 31,
2023 2022 Increase (Decrease)
Revenues 12,870 12,459 $ 411 3 %
Operating expenses (10,604) (10,549) 55 1 %
Other expenses, net (802) (471) 331 70 %
Income taxes (267) (1,000) (733) (73) %
Income attributable to noncontrolling interest (74) (33) 41 124 %
Earnings attributable to FE from continuing operations $ 1,123 $ 406 $ 717 177 %
Earnings attributable to FE from continuing operations was $1,123 million or $1.96 per basic and diluted share in 2023 compared to $406 million or $0.71 per basic and diluted share in 2022, representing an increase of $717 million that was primarily due to the following:
•The absence of an income tax charge of $752 million in 2022, representing the deferred tax liability associated with the deferred tax gain on the 19.9% FET equity interest sale to Brookfield, and a 2023 tax benefit of $65 million, net of a reserve for uncertain tax positions, from the reduction of state income taxes and partial release of a valuation allowance for the expected utilization of state NOL carryforwards based on an assessment of regulated business operations and a change in the composition of a state tax return filing group, partially offset by a $58 million tax charge in 2023 associated with a true-up adjustment associated with the deferred tax gain on the 19.9% FET equity interest sale that closed in May 2022;
•Higher revenues from regulated investment programs, higher weather-adjusted customer usage and demand, the absence of a reserve for customer refunds associated with the FERC Audit, as further discussed below, and a true-up adjustment for the recovery of certain transmission formula rate operating costs during 2023;
•Lower other operating expenses from lower vegetation management expenses, including accelerated work during 2022, fewer regulated generation planned outages, and the absence of a reserve for customer refunds and the reclassification of certain transmission capital assets that are not expected to be recoverable resulting from the FERC Audit that was recognized in the third quarter of 2022; and
•Lower debt redemption costs.
These were partially offset by the following:
•Lower customer usage as a result of the weather;
•Higher other operating expenses from lump sum compensation and severance benefits associated with the PEER program and involuntary separations in 2023, and higher investigation and other related costs associated with the government investigations;
•Higher depreciation expense from a higher asset base;
•Higher pension and OPEB mark-to-market adjustment charges;
•Higher interest expense on short-term borrowings and long-term debt, including the 2026 Convertible Notes issuance;
•Higher non-recoverable charges related to abandoned transmission projects in 2023; and
•The dilutive effect from the 19.9% FET equity interest sale that closed in May 2022.
Detailed segment reporting explanations are included below.
Distribution services by customer class are summarized in the following table:
For the Years Ended December 31,
(In thousands) Actual Weather-Adjusted
Electric Distribution MWh Deliveries(1)
2023 2022 Increase (Decrease) 2023 2022 Increase
Residential 52,217 55,994 (6.7) % 55,909 55,081 1.5 %
Commercial(2)
38,179 39,479 (3.3) % 39,468 39,185 0.7 %
Industrial 52,252 52,008 0.5 % 52,252 52,008 0.5 %
Total Electric Distribution MWh Deliveries 142,648 147,481 (3.3) % 147,629 146,274 0.9 %
(1) Reflects the reclassification of certain Pennsylvania customers from Industrial to Commercial. Due to the January 2024 consolidation of the Pennsylvania Companies, certain customers are classified as Commercial effective June 1, 2024. The MWh deliveries prior to the effective date have been adjusted for comparability.
(2) Includes street lighting.
Residential and commercial distribution deliveries were impacted by lower customer usage as a result of the weather. Cooling degree days in 2023 were 23% below 2022 and 15% below normal. Heating degree days in 2023 were 14% below 2022 and 15% below normal.
The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 16, “Segment Information,” of the Notes to Consolidated Financial Statements.
Summary of Segment Results of Operations - 2024 Compared with 2023
Financial results for FirstEnergy’s business segments for the years ended December 31, 2024 and 2023, were as follows:
2024 Financial Results
(In millions)
Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
Revenues:
Electric $ 6,703 $ 4,815 $ 1,768 $ 9 $ 13,295
Other 160 61 19 (63) 177
Total Revenues 6,863 4,876 1,787 (54) 13,472
Operating Expenses:
Fuel - 464 - - 464
Purchased power 2,219 1,670 - 23 3,912
Other operating expenses 2,408 1,324 359 68 4,159
Provision for depreciation 648 521 336 76 1,581
Amortization (deferral) of regulatory assets, net (171) (66) 6 - (231)
General taxes 752 140 279 41 1,212
Total Operating Expenses 5,856 4,053 980 208 11,097
Other Income (Expense):
Debt redemption costs - - - (85) (85)
Equity method investment earnings, net - - - 58 58
Miscellaneous income, net 124 54 18 (7) 189
Pension and OPEB mark-to-market adjustments 36 26 6 (90) (22)
Interest expense (432) (262) (275) (175) (1,144)
Capitalized financing costs 24 47 60 2 133
Total Other Expense (248) (135) (191) (297) (871)
Income taxes (benefits) 135 153 173 (84) 377
Income attributable to noncontrolling interest - - 149 - 149
Earnings (Loss) Attributable to FE from Continuing Operations $ 624 $ 535 $ 294 $ (475) $ 978
2023 Financial Results
(In millions)
Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
Revenues:
Electric $ 6,690 $ 4,261 $ 1,731 $ 11 $ 12,693
Other 164 59 17 (63) 177
Total Revenues 6,854 4,320 1,748 (52) 12,870
Operating Expenses:
Fuel - 538 - - 538
Purchased power 2,578 1,509 - 21 4,108
Other operating expenses 2,129 1,156 338 (29) 3,594
Provision for depreciation 620 462 304 75 1,461
Amortization (deferral) of regulatory assets, net (259) (10) 8 - (261)
General taxes 734 129 257 44 1,164
Total Operating Expenses 5,802 3,784 907 111 10,604
Other Income (Expense):
Debt redemption costs - - - (36) (36)
Equity method investment earnings, net - - - 175 175
Miscellaneous income (expense), net 84 73 17 (10) 164
Pension and OPEB mark-to-market adjustments (33) (50) (32) 37 (78)
Interest expense (390) (257) (245) (232) (1,124)
Capitalized financing costs 21 35 38 3 97
Total Other Expense (318) (199) (222) (63) (802)
Income taxes (benefits) 147 37 146 (63) 267
Income attributable to noncontrolling interest - - 74 - 74
Earnings (Losses) Attributable to FirstEnergy Corp. from Continuing Operations $ 587 $ 300 $ 399 $ (163) $ 1,123
Changes Between 2024 and 2023
Financial Results
Increase (Decrease) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
(In millions)
Revenues:
Electric $ 13 $ 554 $ 37 $ (2) $ 602
Other (4) 2 2 - -
Total Revenues 9 556 39 (2) 602
Operating Expenses:
Fuel - (74) - - (74)
Purchased power (359) 161 - 2 (196)
Other operating expenses 279 168 21 97 565
Provision for depreciation 28 59 32 1 120
Amortization (deferral) of regulatory assets, net 88 (56) (2) - 30
General taxes 18 11 22 (3) 48
Total Operating Expenses 54 269 73 97 493
Other Income (Expense):
Debt redemption costs - - - (49) (49)
Equity method investment earnings, net - - - (117) (117)
Miscellaneous income (expense), net 40 (19) 1 3 25
Pension and OPEB mark-to-market adjustments 69 76 38 (127) 56
Interest expense (42) (5) (30) 57 (20)
Capitalized financing costs 3 12 22 (1) 36
Total Other Expense 70 64 31 (234) (69)
Income taxes (benefits) (12) 116 27 (21) 110
Income attributable to noncontrolling interest - - 75 - 75
Earnings (Loss) Attributable to FE from Continuing Operations $ 37 $ 235 $ (105) $ (312) $ (145)
Distribution Segment - 2024 Compared with 2023
Distribution segment's earnings attributable to FE from continuing operations increased $37 million in 2024, as compared to 2023, primarily due to higher customer usage as a result of the weather, lower Ohio customer rate credits and lower Pension and OPEB mark-to-market adjustment charges, partially offset by lower weather-adjusted customer usage and demand, lower revenues due to changes in the Ohio DCR that became effective June 1, 2024, and higher operating expenses, including increases in the ARO liability.
Revenues -
Distribution's total revenues increased $9 million as a result of the following sources:
For the Years Ended December 31,
Revenues by Type of Service 2024 2023 Increase (Decrease)
(In millions)
Distribution services $ 4,180 $ 3,847 $ 333
Generation sales:
Retail 2,517 2,823 (306)
Wholesale 6 20 (14)
Total generation sales 2,523 2,843 (320)
Other 160 164 (4)
Total Revenues $ 6,863 $ 6,854 $ 9
Distribution services revenues increased $333 million in 2024, as compared to 2023, primarily due to higher customer usage as a result of the weather, higher rider revenues associated with a Pennsylvania regulated investment program, and lower customer credits associated with the PUCO-approved Ohio Stipulation. Additionally, revenues increased due to the higher recovery of transmission expenses, and other FE PA rider rate adjustments, which have no material impact to earnings. Higher distribution services revenues were partially offset by lower weather-adjusted customer usage and demand, and lower revenues associated with changes to the Ohio DCR as a result of the PUCO’s ESP V order that became effective June 1, 2024.
Generation sales revenues decreased $320 million in 2024, as compared to 2023, primarily due to lower retail generation sales as a result of increased customer shopping, partially offset by higher non-shopping generation auction rates. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA in 2024, as compared to 2023, increased to 90% from 77% in Ohio and increased to 63% from 62% in Pennsylvania. Retail and wholesale generation sales revenue have no material impact to earnings.
Operating Expenses -
Total operating expenses increased $54 million, primarily due to the following:
•Purchased power costs, which have no material impact to earnings, decreased $359 million in 2024, as compared to 2023, primarily due to lower generation sales volumes, as described above, and decreased capacity expenses, partially offset by higher unit costs.
•Other operating expenses increased $279 million in 2024, as compared to 2023, primarily due to:
•Higher network transmission expenses of $154 million, which are deferred for future recovery, resulting in no material impact to earnings;
•$46 million charge related to changes in ARO liabilities associated with final CCR rules;
•$32.5 million contribution commitment by the Ohio Companies, as a result of the PUCO's Ohio ESP V order;
•$31 million impairment charge related to the Akron general office in the third quarter of 2024;
•Higher planned vegetation management expenses of $57 million;
•Higher energy efficiency and other state mandated program costs of $8 million, which were deferred for future recovery;
•Higher storm restoration expenses of $48 million, of which $38 million were deferred for future recovery; and
•Higher uncollectible expenses of $40 million, of which $14 million were deferred for future recovery, primarily due to a reduction to the allowance during 2023.
This increase was partially offset by:
•Lower other operating expenses of $138 million, primarily due to lower labor and benefits expenses, including those associated with the PEER program and separation-related costs.
•Depreciation expense increased $28 million in 2024, as compared to 2023, primarily due to a higher asset base.
•Deferral of regulatory assets decreased $88 million in 2024, as compared to 2023, primarily due to a $17 million decrease of certain Tax Act savings deferrals to FE PA customers, $69 million decrease from lower net generation and transmission related deferrals, and $40 million related to net decreases in other deferrals, partially offset by $38 million increase due to higher deferral of storm related expenses.
•General taxes increased $18 million in 2024, as compared to 2023, primarily due to higher gross receipts taxes.
Other Expense -
Other expense decreased $70 million in 2024, as compared to 2023, primarily due to $69 million in lower pension and OPEB mark-to-market adjustment charges.
Income Taxes
Distribution segment's effective tax rate was 17.8% and 20.0% for 2024 and 2023, respectively, primarily due to the remeasurement of excess deferred income taxes in 2024.
Integrated Segment - 2024 Compared with 2023
Integrated segment’s earnings attributable to FE from continuing operations increased $235 million in 2024, as compared to 2023, primarily from the implementation of base rate cases, higher customer usage and demand, higher revenues from regulated investment programs, and lower Pension and OPEB mark-to-market adjustment charges, partially offset by higher operating expenses, including increases in the ARO liability, and a higher effective tax rate discussed below.
Revenues -
Integrated segment’s total revenues increased $556 million as a result of the following sources:
For the Years Ended December 31,
Revenues by Type of Service 2024 2023 Increase (Decrease)
(In millions)
Distribution services (1)
$ 1,600 $ 1,411 $ 189
Generation sales:
Retail 2,689 2,324 365
Wholesale 146 208 (62)
Total generation sales 2,835 2,532 303
Transmission revenues:
JCP&L 243 206 37
MP & PE 137 112 25
Total transmission revenues 380 318 62
Other 61 59 2
Total Revenues $ 4,876 $ 4,320 $ 556
(1) Includes $10 million of ARP revenues in 2024, related to lost distribution revenues associated with energy efficiency in New Jersey.
Distribution services revenues increased $189 million in 2024, as compared to 2023, primarily due to higher revenues from the implementation of base rate cases, higher customer usage as a result of the weather, higher weather-adjusted customer usage and demand, 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 $303 million in 2024, as compared to 2023, primarily due to higher retail revenues, partially offset by lower wholesale revenues.
•Retail generation sales increased $365 million in 2024, as compared to 2023, primarily due to higher customer usage as a result of the weather and higher non-shopping generation auction rates. Retail generation sales, other than those in West Virginia, have no material impact to earnings.
•Wholesale generation revenues decreased $62 million in 2024, as compared to 2023, primarily due to lower capacity revenues and lower market prices, partially offset by higher sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.
Transmission revenues increased $62 million in 2024, as compared to 2023, primarily due to higher rate base from regulated investment programs.
Operating Expenses -
Total operating expenses increased $269 million, primarily due to:
•Fuel costs decreased $74 million in 2024, as compared to 2023, primarily due to lower unit costs and 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 $161 million in 2024, as compared to 2023, primarily due to higher unit costs and volumes, partially offset by lower capacity expenses.
•Other operating expenses increased $168 million in 2024, as compared to 2023, primarily due to:
•$53 million charge at JCP&L in the first quarter of 2024 associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the base rate case settlement agreement, to be disallowed from future recovery;
•Higher storm restoration expenses of $80 million, of which $63 million was deferred for future recovery;
•Higher network transmission expenses of $42 million, which were deferred for future recovery, resulting in no material impact to earnings;
•$16 million charge related to changes in ARO liabilities associated with final CCR rules;
•$17 million impairment charge related to the Akron general office in the third quarter of 2024;
•Higher planned vegetation management costs of $15 million, of which $8 million were deferred for future recovery;
•Higher uncollectible expenses of $17 million, which were mostly deferred for future recovery, primarily due to a reduction to the allowance during 2023; and
•Higher energy efficiency and other state mandated program costs of $27 million, which were deferred for future recovery, resulting in no material impact to earnings.
This increase was partially offset by:
•Lower other operating and maintenance expenses of $99 million, primarily due to lower labor and benefit expenses, including those associated with the PEER program and separation-related costs and lower regulated generation costs.
•Depreciation expense increased $59 million in 2024, as compared to 2023, primarily due to a higher asset base.
•Deferral of regulatory assets increased $56 million in 2024, as compared to 2023, primarily due to:
•$63 million due to higher deferral of storm related expenses;
•$60 million due to the approval in the first quarter of 2024 to recover costs of certain retired generation stations by the WVPSC;
•$31 million related to net increases in other deferrals; and
•$12 million due to higher energy efficiency related deferrals.
This increase was partially offset by:
•$98 million due to lower net generation and transmission related deferrals; and
•$12 million due to higher vegetation management program-related amortizations.
•General taxes increased $11 million in 2024, as compared to 2023, primarily due to higher gross receipts taxes.
Other Expense -
Other expense decreased $64 million in 2024, as compared to 2023, primarily due to $76 million in lower pension and OPEB mark-to-market adjustment charges, higher interest expense on short-term borrowings and higher non-recoverable charges related to abandoned transmission projects, partially offset by higher capitalized interest.
Income Taxes -
Integrated segment’s effective tax rate was 22.2% and 11.0% in 2024 and 2023, respectively. The increase in the effective tax rate is primarily due to the absence of discrete tax benefits related to the expected utilization of state NOL carryforwards and the release of an uncertain tax position related to state taxes recognized in 2023, partially offset by a remeasurement of excess deferred income taxes in 2024.
Stand-Alone Transmission Segment - 2024 Compared with 2023
Stand-Alone Transmission’s earnings attributable to FE from continuing operations decreased $105 million in 2024, as compared to 2023, primarily due to the dilutive effect of the FET Equity Interest Sale that closed in March 2024, and a charge for an expected refund, with interest, as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership, partially offset by higher revenues from regulated capital investments that increased rate base.
Revenues -
Total revenues increased $39 million in 2024, as compared to 2023, primarily due to higher rate base and recovery of higher transmission operating expenses partially offset by a charge for an expected refund as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership. Revenues by transmission asset owner are shown in the following table:
For the Years Ended December 31,
Revenues by Transmission Asset Owner 2024 2023 Increase (Decrease)
(In millions)
ATSI $ 990 $ 974 $ 16
TrAIL 274 284 (10)
MAIT 440 399 41
KATCo 85 89 (4)
Other (2) 2 (4)
Total Revenues $ 1,787 $ 1,748 $ 39
Operating Expenses -
Total operating expenses increased $73 million in 2024, as compared to 2023, primarily due to higher operation and maintenance costs, higher property taxes and depreciation due to a higher asset base and a $11 million charge from FESC in connection with its planned exit from the Akron general office. Other than the general office charge, nearly all operating expenses are recovered through formula rates, resulting in no material impact to earnings.
Other Expense -
Total other expense decreased $31 million in 2024, as compared to 2023, primarily due to lower pension and OPEB mark-to-market adjustment charges of $38 million, partially offset by higher net financing costs associated with new debt issuances and interest related to the expected refund associated with the Sixth Circuit ruling noted above.
Income Taxes -
Stand-Alone Transmission's effective tax rate was 28.1% and 23.6% for 2024 and 2023, respectively. The increase in the effective tax rate was primarily due to discrete tax charges related to the FET Equity Interest Sale in 2024, as well as the absence of a discrete tax benefit related to the expected utilization of state NOL carryforwards recognized in 2023.
Corporate/Other - 2024 Compared with 2023
Financial results from Corporate/Other resulted in a $312 million increase in losses attributable to FE from continuing operations for 2024 compared to 2023, primarily due to:
•$120 million related to a civil penalty with the SEC and a settlement with the OAG's office as further discussed below in “Outlook - Other Legal Proceedings”;
•$111 million (after-tax) charge related to changes in ARO liabilities associated with final CCR rules and future expected costs to remediate McElroy’s Run;
•$99 million (after-tax) from higher pension and OPEB mark-to-market adjustment charges;
•$80 million (after-tax) in lower investment earnings related to FEV’s equity method investment in Global Holding;
•$38 million (after-tax) of higher debt redemption costs;
•$10 million (after-tax) related to an impairment charge recognized in the fourth quarter of 2024 associated with FirstEnergy's actions to exit FEV's equity method investment in Global Holding;
•$9 million (after-tax) of higher investigation and other related costs associated with the government investigations; and
•Lower income tax benefits in 2024 as a result of tax charges related to the PA Consolidation and FET Equity Interest Sale, the absence of a reduction in state income taxes and release of valuation allowances recognized in 2023, partially offset by discrete tax benefits recognized in 2024 associated with certain equity method investments.
The increase in losses were partially offset by:
•$116 million (after-tax) of net proceeds from the shareholder derivative lawsuit settlement as described below in “Outlook - Other Legal Proceedings”;
•$23 million (after-tax) of lower other operating expenses primarily related to the absence of expenses associated with the cancellation of certain sponsorship agreements in 2023;
•$19 million (after-tax) of higher interest income on the FET Equity Interest Sale promissory notes; and
•$16 million (after-tax) of lower interest expense as a result of the redemption of certain FE long-term debt and lower short-term borrowings.
Summary of Segment Results of Operations - 2023 Compared with 2022
Financial results for FirstEnergy’s business segments for the years ended December 31, 2023 and 2022, were as follows:
2023 Financial Results
(In millions)
Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
Revenues:
Electric $ 6,690 $ 4,261 $ 1,731 $ 11 $ 12,693
Other 164 59 17 (63) 177
Total Revenues 6,854 4,320 1,748 (52) 12,870
Operating Expenses:
Fuel - 538 - - 538
Purchased power 2,578 1,509 - 21 4,108
Other operating expenses 2,129 1,156 338 (29) 3,594
Provision for depreciation 620 462 304 75 1,461
Amortization (deferral) of regulatory assets, net (259) (10) 8 - (261)
General taxes 734 129 257 44 1,164
Total Operating Expenses 5,802 3,784 907 111 10,604
Other Income (Expense):
Debt redemption costs - - - (36) (36)
Equity method investment earnings, net - - - 175 175
Miscellaneous income (expense), net 84 73 17 (10) 164
Pension and OPEB mark-to-market adjustments (33) (50) (32) 37 (78)
Interest expense (390) (257) (245) (232) (1,124)
Capitalized financing costs 21 35 38 3 97
Total Other Expense (318) (199) (222) (63) (802)
Income taxes (benefits) 147 37 146 (63) 267
Income attributable to noncontrolling interest - - 74 - 74
Earnings (Loss) Attributable to FE from Continuing Operations $ 587 $ 300 $ 399 $ (163) $ 1,123
2022 Financial Results
(In millions)
Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
Revenues:
Electric $ 6,267 $ 4,425 $ 1,581 $ 27 $ 12,300
Other 158 45 16 (60) 159
Total Revenues 6,425 4,470 1,597 (33) 12,459
Operating Expenses:
Fuel - 730 - - 730
Purchased power 2,236 1,606 - 21 3,863
Other operating expenses 2,094 1,226 428 69 3,817
Provision for depreciation 593 430 277 75 1,375
Amortization (deferral) of regulatory assets, net (241) (128) 4 - (365)
General taxes 714 123 247 45 1,129
Total Operating Expenses 5,396 3,987 956 210 10,549
Other Income (Expense):
Debt redemption costs - - - (171) (171)
Equity method investment earnings, net - - - 168 168
Miscellaneous income, net 165 102 55 93 415
Pension and OPEB mark-to-market adjustments (12) (43) (10) 137 72
Interest expense (325) (225) (263) (226) (1,039)
Capitalized financing costs 19 28 36 1 84
Total Other Income (Expense) (153) (138) (182) 2 (471)
Income taxes 202 80 111 607 1,000
Income attributable to noncontrolling interest - - 33 - 33
Earnings (Losses) Attributable to FirstEnergy Corp. from Continuing Operations $ 674 $ 265 $ 315 $ (848) $ 406
Changes Between 2023 and 2022
Financial Results
Increase (Decrease) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
(In millions)
Revenues:
Electric $ 423 $ (164) $ 150 $ (16) $ 393
Other 6 14 1 (3) 18
Total Revenues 429 (150) 151 (19) 411
Operating Expenses:
Fuel - (192) - - (192)
Purchased power 342 (97) - - 245
Other operating expenses 35 (70) (90) (98) (223)
Provision for depreciation 27 32 27 - 86
Amortization (deferral) of regulatory assets, net (18) 118 4 - 104
General taxes 20 6 10 (1) 35
Total Operating Expenses 406 (203) (49) (99) 55
Other Income (Expense):
Debt redemption costs - - - 135 135
Equity method investment earnings, net - - - 7 7
Miscellaneous income (expense), net (81) (29) (38) (103) (251)
Pension and OPEB mark-to-market adjustments (21) (7) (22) (100) (150)
Interest expense (65) (32) 18 (6) (85)
Capitalized financing costs 2 7 2 2 13
Total Other Income (Expense) (165) (61) (40) (65) (331)
Income taxes (benefits) (55) (43) 35 (670) (733)
Income attributable to noncontrolling interest - - 41 - 41
Earnings (Loss) Attributable to FE from Continuing Operations $ (87) $ 35 $ 84 $ 685 $ 717
Distribution Segment - 2023 Compared with 2022
Distribution segment's earnings attributable to FE from continuing operations decreased $87 million in 2023, as compared to 2022, primarily due to lower customer usage as a result of the weather, lower net pension and OPEB credits, and higher interest expense and costs from the PEER, partially offset by lower other operating expenses, higher revenues from regulated investment programs and higher weather-adjusted customer usage and demand.
Revenues -
Distribution's total revenue increased $429 million from the following sources:
For the Years Ended December 31,
Revenues by Type of Service 2023 2022 Increase
(In millions)
Distribution services $ 3,847 $ 3,689 $ 158
Generation sales:
Retail 2,823 2,559 264
Wholesale 20 19 1
Total generation sales 2,843 2,578 265
Other 164 158 6
Total Revenues $ 6,854 $ 6,425 $ 429
Distribution services revenues increased $158 million in 2023, as compared to 2022, primarily due to higher weather-adjusted customer usage and demand, higher rider revenues associated with a Pennsylvania regulated investment program, and lower customer credits associated with the PUCO-approved Ohio Stipulation. Higher distribution services revenues were partially offset by lower customer usage as a result of the weather and lower recovery of transmission expenses, which have no material impact to earnings.
Generation sales revenues increased $265 million in 2023, as compared to 2022, primarily due to higher retail generation sales as a result of higher non-shopping generation auction rates, partially offset by lower customer usage as a result of the weather and increased customer shopping in Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWh deliveries in Pennsylvania increased to 62% in 2023 as compared to 60% in 2022. Retail and wholesale generation sales revenue have no material impact to earnings.
Operating Expenses -
Total operating expenses increased $406 million primarily due to the following:
•Purchased power costs, which have no material impact to earnings, increased $342 million in 2023, as compared to 2022, primarily due to higher volumes, partially offset by lower unit costs and capacity expenses.
•Other operating expenses increased $35 million in 2023, as compared to 2022, primarily due to:
•Lump sum compensation and severance benefits of $24 million associated with the PEER program and involuntary separations in 2023;
•Higher energy efficiency and other state mandated program costs of $26 million, which were deferred for future recovery; and
•Higher storm restoration expenses of $95 million, which were mostly deferred for future recovery, resulting in no material impact to earnings recovery;
This increase was partially offset by:
•Lower vegetation management expenses of $72 million, including accelerated work during 2022;
•Lower network transmission expenses of $11 million, which are deferred for future recovery, resulting in no material impact to earnings; and
•Lower uncollectible expenses of $27 million, of which $4 million was deferred for future recovery.
•Depreciation expense increased $27 million in 2023, as compared to 2022, primarily due to a higher asset base.
•Deferral of regulatory assets increased $18 million in 2023, as compared to 2022, primarily due to:
•$83 million net increase due to higher generation and transmission related deferrals; and
•$98 million increase due to higher deferral of storm related expenses;
This increase was partially offset by:
•$100 million decrease due to the absence of a return of certain Tax Act savings to Pennsylvania customers in 2022;
•$51 million decrease due to the absence of the customer refunds associated with the Ohio Stipulation; and
•$12 million net decreases in other deferrals.
•General taxes increased $20 million in 2023, as compared to 2022, primarily due to higher gross receipts taxes and Ohio property taxes, partially offset by lower Ohio kWh taxes.
Other Expense -
Other expense increased $165 million in 2023, as compared to 2023, primarily due to lower net pension and OPEB non-service credits, a $21 million change in pension and OPEB mark-to-market adjustment charges, higher net interest expense associated with new long-term issuances and higher short-term borrowings, and a charge from an environmental agreement requiring a $10 million contribution to the EPA associated with a former generation plant of OE.
Income Taxes
Distribution segment's effective tax rate was 20.0% and 23.1% for 2023 and 2022, respectively.
Integrated Segment - 2023 Compared with 2022
Integrated segment’s earnings attributable to FE from continuing operations increased $35 million in 2023, as compared to 2022, primarily due to lower other operating expenses, higher revenues from regulated investment programs and higher weather-adjusted customer usage and demand, partially offset by lower customer usage as a result of the weather, lower net pension and OPEB credits, and higher interest expense and costs from the PEER.
Revenues -
Integrated segment’s total revenues decreased $150 million as a result of the following sources:
For the Years Ended December 31,
Revenues by Type of Service 2023 2022 Increase (Decrease)
(In millions)
Distribution services $ 1,411 $ 1,459 $ (48)
Generation sales:
Retail 2,324 2,209 115
Wholesale 208 475 (267)
Total generation sales 2,532 2,684 (152)
Transmission revenues:
JCP&L 206 203 3
MP & PE 112 79 33
Total transmission revenues 318 282 36
Other 59 45 14
Total Revenues $ 4,320 $ 4,470 $ (150)
Distribution services revenues decreased $48 million in 2023, as compared to 2022, primarily due to lower customer usage as a result of the weather and lower recovery of transmission expenses, partially offset by higher rider revenues associated with certain investment programs, and higher weather-adjusted customer usage and demand.
Generation sales revenues decreased $152 million in 2023, as compared to 2022, primarily due to lower wholesale revenues, partially offset by higher retail revenues.
•Retail generation sales increased $115 million in 2023, as compared to 2022, primarily due to higher non-shopping generation auction rates, partially offset by lower sales volumes. Retail generation sales, other than those in West Virginia, have no material impact to earnings.
•Wholesale generation revenues decreased $267 million in 2023, as compared to 2022, primarily due to lower capacity revenues, market prices and sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.
Transmission revenues increased $36 million in 2023, as compared to 2022, primarily due to higher rate base from regulated investment programs.
Operating Expenses -
Total operating expenses decreased $203 million, primarily due to:
•Fuel costs decreased $192 million in 2023, as compared to 2022, primarily due to lower unit costs and consumption volumes. Due to the ENEC, fuel expense has no material impact to earnings.
•Purchased power costs, which have no material impact to earnings, decreased $97 million in 2023, as compared to 2022, primarily due to lower unit costs and capacity expenses, partially offset by higher volumes.
•Other operating expenses decreased $70 million in 2023, as compared to 2022, primarily due to:
•Lower network transmission expenses of $30 million, which are deferred for future recovery, resulting in no material impact to earnings;
•Lower uncollectible expenses of $19 million, which are deferred for future recovery, resulting in no material impact to earnings;
•Lower storm restoration expenses of $10 million, which were mostly deferred for future recovery, resulting in no material impact to earnings; and
•Lower expenses of $60 million, primarily due to the absence of the reclassification of certain transmission capital assets to operating expenses as a result of the FERC Audit.
This decrease was partially offset by:
•Lump sum compensation and severance benefits of $18 million associated with the PEER program and involuntary separations in 2023;
•Higher vegetation management in West Virginia, energy efficiency and other state mandated program costs of $17 million, which were deferred for future recovery; and
•Higher other operating expenses of $14 million, primarily due to higher contractor expenses, partially offset by fewer regulated generation planned outages.
•Depreciation expense increased $32 million in 2023, as compared to 2022, primarily due to a higher asset base.
•Deferral of regulatory assets decreased $118 million in 2023, as compared to 2022, primarily due to:
•$181 million net decrease due to lower generation and transmission related deferrals; and
•$8 million decrease due to lower deferral of storm related expenses.
This decrease was partially offset by:
•$40 million increase due to lower vegetation management and other program-related amortizations;
•$15 million increase due to higher energy efficiency related deferrals; and
•$16 million related to net increases in other deferrals.
•General taxes increased $6 million in 2023, as compared to 2022, primarily due to higher payroll taxes.
Other Expense -
Other expense increased $61 million in 2023, as compared to 2022, primarily due to lower net pension and OPEB non-service credits, a $7 million change in pension and OPEB mark-to-market adjustment charges, and higher net interest expense associated with new long-term issuances and higher short-term borrowings.
Income Taxes -
Integrated segment’s effective tax rate was 11.0% and 23.2% in 2023 and 2022, respectively. The decrease in the effective tax rate is primarily due to discrete tax benefits related to the expected utilization of state NOL carryforwards and the release of an uncertain tax position related to state taxes recognized in 2023.
Stand-Alone Transmission Segment - 2023 Compared with 2022
Stand-Alone Transmission's earnings attributable to FE from continuing operations increased $84 million in 2023, as compared to 2022, primarily due to the absence of a reserve for customer refunds and the reclassification of certain transmission capital assets that are not expected to be recoverable resulting from the FERC Audit that was recognized in the third quarter of 2022, as further discussed below and as a result of regulated capital investments that increased rate base, partially offset by the dilutive effect of the 19.9% sale of FET equity interest that closed in May 2022.
Revenues -
Total revenues increased $151 million in 2023, as compared to 2022, primarily due to the absence of a reserve for customer refunds associated with the FERC Audit, as further discussed below, a true-up adjustment for the recovery of certain transmission formula rate operating costs during 2023 and a higher rate base.
Revenues by transmission asset owner are shown in the following table:
For the Years Ended December 31,
Revenues by Transmission Asset Owner 2023 2022 Increase
(In millions)
ATSI $ 974 $ 918 $ 56
TrAIL 284 275 9
MAIT 399 344 55
KATCo 89 59 30
Other 2 1 1
Total Revenues $ 1,748 $ 1,597 $ 151
Operating Expenses -
Total operating expenses decreased $49 million in 2023, as compared to 2022, primarily due to the absence of the reclassification of certain transmission capital assets to operating expenses as a result of the FERC Audit, as further discussed below, partially offset by higher depreciation and property tax expenses from a higher asset base. Other than the write-off of nonrecoverable transmission assets, nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expense -
Total other expense increased $40 million in 2023, as compared to 2022, primarily due to a change in pension and OPEB mark-to-market adjustment charges of $22 million and pension and OPEB non-service credits partially offset by lower interest on long-term debt and borrowings under the revolving credit facilities and higher unregulated money pool interest income at FET.
Income Taxes -
Stand-Alone Transmission's effective tax rate was 23.6% and 24.2% for 2023 and 2022, respectively.
Corporate/Other - 2023 Compared with 2022
Financial results from Corporate/Other resulted in a $685 million decrease in losses attributable to FE from continuing operations for 2023 compared to 2022, primarily due to:
•Lower income tax expense primarily due to the absence of an income tax charge of $752 million in 2022, representing the deferred tax liability associated with the deferred tax gain on the 19.9% FET equity interest sale to Brookfield, and a 2023 tax benefit of $65 million, net of a reserve for uncertain tax positions, from the reduction of state income taxes and partial release of a valuation allowance for the expected utilization of state NOL carryforwards based on an assessment of regulated business operation and the composition of a state tax return filing group, partially offset by a $58 million tax charge in 2023 associated with a true-up adjustment associated with the deferred tax gain on the 19.9% FET equity
interest sale;
•$105 million (after-tax) of lower debt redemption costs;
•$6 million (after-tax) related to higher investment earnings on corporate-owned life insurance policies; and
•$6 million (after-tax) in higher investment earnings related to FEV’s equity method investment in Global Holding.
The decrease in losses were partially offset by:
•$78 million (after-tax) related to lower pension and OPEB mark-to-market adjustment charges;
•$23 million (after-tax) of higher other operating expenses primarily related to the expenses associated with the cancellation of certain sponsorship agreements in 2023;
•$20 million (after-tax) from lower pension and OPEB non-service credits;
•$16 million (after-tax) of higher investigation and other related costs associated with the government investigations;
•$8 million (after-tax) for a charge associated with an update to the McElroy’s Run ARO; and
•$5 million (after-tax) of higher interest expense from the 2026 Convertible Notes issuance.
REGULATORY ASSETS AND LIABILITIES
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Electric Companies and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.
Management assesses the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability relate to changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets and liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2024 and 2023, and the changes during the year 2024:
As of December 31,
Net Regulatory Assets (Liabilities) by Source 2024 2023 Change
(In millions)
Customer payables for future income taxes $ (2,234) $ (2,382) $ 148
Spent nuclear fuel disposal costs (72) (83) 11
Asset removal costs (681) (652) (29)
Deferred transmission costs 190 286 (96)
Deferred generation costs 481 572 (91)
Deferred distribution costs 287 247 40
Storm-related costs 1,015 799 216
Energy efficiency program costs 349 198 151
New Jersey societal benefit costs 87 79 8
Vegetation management costs 125 102 23
Other 75 (11) 86
Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (378) $ (845) $ 467
The following is a description of the regulatory assets and liabilities described above:
Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to federal and state tax rate changes such as the Tax Act and Pennsylvania House Bill 1342. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset.
Spent nuclear fuel disposal costs - Reflects amounts collected from customers, and the investment income, losses and changes in fair value of the trusts for spent nuclear fuel disposal costs related to former nuclear generating facilities, Oyster Creek and Three Mile Island Unit 1.
Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement.
Deferred transmission costs - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed, including amounts at December 31, 2023, expected to be refunded to, or recoverable from, wholesale transmission customers resulting from the FERC Audit, which amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods. Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.
Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. Generally, the ENEC rate is updated annually.
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 $402 million and $254 million are currently being recovered through rates as of December 31, 2024 and 2023, respectively.
Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including New Jersey energy efficiency and renewable energy programs, FE PA's Energy Efficiency and Conservation programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland Surcharge. Investments in certain of these energy efficiency programs earn a long-term return.
New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and the New Jersey Clean Energy Program.
Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey, 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 net regulatory assets that do not earn a current return as of December 31, 2024 and 2023, of which approximately $698 million and $371 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:
Regulatory Assets by Source Not Earning a As of December 31,
Current Return 2024 2023 Change
(In millions)
Deferred transmission costs $ 8 $ 6 $ 2
Deferred generation costs 314 432 (118)
Deferred distribution costs 153 68 85
Storm-related costs 694 602 92
Vegetation management 16 21 (5)
Other 58 68 (10)
Regulatory Assets Not Earning a Current Return $ 1,243 $ 1,197 $ 46
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction and other investment expenditures, scheduled debt maturities and interest payments, dividend payments and potential contributions to its pension plan.
FE and its subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2025 and beyond, FE and its subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its subsidiaries to, among other things, fund capital expenditures and other capital-like investments, and
refinance short-term and maturing long-term debt, subject to market conditions and other factors. FE may utilize instruments other than senior notes to fund its liquidity and capital requirements, including hybrid securities.
Capital investments by business segment are included below:
Business Segment 2022 Actual
2023 Actual
Actual
(In millions)
Distribution $ 1,047 $ 1,020 $ 1,285
Integrated(1)
1,111 1,336 1,690
Stand-Alone Transmission 1,005 1,273 1,427
Corporate/Other 81 118 97
Total $ 3,244 $ 3,747 $ 4,499
(1) Includes capital expenditures and capital-like investments that earn a return.
Capital investment forecasts for the years ended 2025, 2026, 2027, 2028, and 2029 by business segment are included below:
Business Segment 2025
Forecast
2026 Forecast
2027 Forecast
2028 Forecast
2029 Forecast
(In millions)
Distribution $ 1,405 $ 1,390 $ 1,460 $ 1,540 $ 1,645
Integrated(1)
1,835 1,910 2,150 2,410 2,530
Stand-Alone Transmission(2)
1,650 1,790 1,885 1,980 2,180
Corporate/Other 85 70 75 65 70
Total $ 4,975 $ 5,160 $ 5,570 $ 5,995 $ 6,425
(1) Includes capital expenditures and capital-like investments that earn a return.
(2) Consolidated plan includes Brookfield's non-controlling interest in FET
In alignment with FirstEnergy’s strategy to invest in its segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated subsidiaries to issue and/or refinance debt.
Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes. Interest income associated with the promissory notes was $24 million for the year ended December 31, 2024 and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.
On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies.
Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.
Economic conditions have stabilized across numerous material categories, but not all lead times have returned to pre-pandemic levels. Several key suppliers have seen improvements with capacity, but FirstEnergy continues to monitor the situation as demand increases across the industry, including due to data center usage. Inflationary pressures have moderated, which has improved the cost of materials, but certain categories have remained elevated. 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 FirstEnergy’s results of operations, cash flow and financial condition.
In February 2025, the new U.S. presidential administration announced the imposition of widespread and substantial tariffs on imports, with plans for additional tariffs to potentially be adopted in the future. Although certain of these tariffs were subsequently temporarily stayed, the situation is dynamic and subject to rapid change. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on FirstEnergy's results of operations, cash flow and financial condition.
In December 2023, FirstEnergy, executed a lift-out transaction with Banner Life Insurance Company and Reinsurance Group of America that transferred approximately $683 million of plan assets and $719 million of plan obligations, associated with approximately 1,900 former competitive generation employees, who will assume future and full responsibility to fund and administer their benefit payments. There was no change to the pension benefits for any participants as a result of the transfer. The transaction was funded by pension plan assets and resulted in a pre-tax gain of approximately $36 million, which was included in the fourth quarter 2023 pension and OPEB mark-to-market adjustment charge.
Additionally, in January 2025, FirstEnergy executed a lift-out transaction with MetLife, that 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. Similar to the lift-out in 2023, 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 December 31, 2024, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to accounts payable, current portion of long-term debt, short-term borrowings and accrued interest, taxes, and compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below.
Short-Term Borrowings / Revolving Credit Facilities
On October 24, 2024, FE and certain of its subsidiaries entered into the following amendments to each of the 2021 Credit Facilities to, among other things: (i) extend the maturity date of the 2021 Credit Facilities for an additional one-year period, from October 18, 2027 to October 18, 2028, and (ii) increase the borrowing limit of the JCP&L credit facility from $500 million to $750 million. Also on October 24, 2024, each of FET and KATCo entered into amendments of the 2023 Credit Facilities, to, among other things, extend the maturity date of the 2023 Credit Facilities for an additional one-year period, from October 20, 2028 to October 20, 2029 and from October 20, 2027 to October 20, 2028, for the FET credit facility and KATCo credit facility, respectively.
The 2021 Credit Facilities and 2023 Credit Facilities, as amended on October 24, 2024, are as follows:
•FE, $1.0 billion revolving credit facility;
•FET, $1.0 billion revolving credit facility;
•Ohio Companies, $800 million revolving credit facility;
•FE PA, $950 million revolving credit facility;
•JCP&L, $750 million revolving credit facility;
•MP and PE, $400 million revolving credit facility;
•ATSI, MAIT and TrAIL, $850 million revolving credit facility; and
•KATCo, $150 million revolving credit facility.
Borrowings under the 2021 Credit Facilities and 2023 Credit Facilities may be used for working capital and other general corporate purposes. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 2021 Credit Facilities and 2023 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities and 2023 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 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.
The 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. 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 $550 million and $775 million of outstanding short-term borrowings as of December 31, 2024 and 2023, respectively. FirstEnergy’s available liquidity from external sources as of February 25, 2025, was as follows:
Revolving Credit Facilities Maturity Commitment Available Liquidity
(In millions)
FE October 2028 $ 1,000 $ 997
FET October 2029 1,000 625
Ohio Companies October 2028 800 312
FE PA October 2028 950 931
JCP&L October 2028 750 722
MP and PE October 2028 400 198
ATSI, MAIT and TrAIL October 2028 850 844
KATCo October 2028 150 150
Subtotal $ 5,900 $ 4,779
Cash and Cash equivalents - 36
Total $ 5,900 $ 4,815
The following table summarizes the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of December 31, 2024:
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 39.5 %
CEI(1)
500 300 36.8 %
FET N/A 1,000 65.1 %
FE PA(1)
1,250 950 47.3 %
JCP&L(1)
1,000 750 32.4 %
KATCo(1)
200 150 30.5 %
MAIT(1)
400 350 38.0 %
MP(1)
500 250 51.4 %
OE(1)
500 300 53.5 %
PE(1)
150 150 51.7 %
TE(1)
300 200 47.8 %
TrAIL(1)
400 150 39.6 %
(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 ending December 31, 2021. FE's consolidated interest coverage ratio as of December 31, 2024 was approximately 4.5 times.
Subject to each borrower’s sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the 2021 Credit Facilities and 2023 Credit Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the 2021 Credit Facilities and 2023 Credit Facilities and against the applicable borrower’s borrowing sublimit. As of December 31, 2024, FirstEnergy had $170 million in outstanding LOCs, $139 million of which are issued under the revolving credit facilities.
Revolving Credit Facility LOC Availability LOC Utilized
as of December 31, 2024
(In millions)
FE $ 100 $ 3
FET 100 -
Ohio Companies 150 31
FE PA 200 19
JCP&L 100 28
MP and PE 100 52
ATSI, MAIT and TrAIL 200 6
KATCo 35 -
The 2021 Credit Facilities and 2023 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the 2021 Credit Facilities and the 2023 Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 2021 Credit Facilities and 2023 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of December 31, 2024, FE was in compliance with its applicable consolidated interest coverage ratio and the borrowers in each case as defined under the 2021 Credit Facilities and 2023 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
2024 2023 2024 2023
For the Years Ended December 31, 5.74 % 6.30 % 6.44 % 6.01 %
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 February 25, 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 2021 Credit Facilities and 2023 Credit Facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments under the 2021 Credit Facilities and 2023 Credit Facilities are based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s. The fees paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.
The interest rates payable on approximately $2.1 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable governing documents. Generally, a one-notch downgrade by the applicable rating agency may result in a 25 basis point coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.
Debt capacity is subject to the consolidated interest coverage ratio in FE's credit facility. As of December 31, 2024, FirstEnergy could incur approximately $930 million of incremental interest expense or incur an approximate $2.3 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, including contracts executed in connection with certain of the planned construction expenditures.
As of December 31, 2024 (Undiscounted): Total 2025 2026-2027 2028-2029 Thereafter
(In millions)
Long-term debt(1)
$ 23,594 $ 973 $ 4,879 $ 3,517 $ 14,225
Short-term borrowings 550 550 - - -
Interest on long-term debt 9,994 996 1,730 1,404 5,864
Operating leases(2)
282 61 104 71 46
Finance leases(2)
15 4 7 4 -
Fuel and purchased power(3)
1,494 221 429 341 503
Committed investments(4)
7,284 3,247 2,555 1,482 -
Pension funding(5)
1,791 - 311 587 893
Total $ 45,004 $ 6,052 $ 10,015 $ 7,406 $ 21,531
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases.
(2) See Note 8, "Leases," of the Notes to Consolidated Financial Statements.
(3) Based on estimated annual amounts under contract with fixed or minimum quantities, and includes payment obligations under termination agreements.
(4) Amounts represent committed capital expenditures and other capital-like investments that earn a return.
(5) As discussed further below, FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027.
Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Electric Companies and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. Although actual amounts will be determined by future customer behavior, consumption levels and power prices, management currently estimates these cash outlays will be approximately $4.1 billion in 2025.
The table above also excludes AROs, reserves for litigation, injuries and damages and environmental remediation since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year and/or the application of the corporate AMT which, as further discussed below, is uncertain and subject to the issuance of future U.S. Treasury regulations.
FirstEnergy’s pension funding policy is based on actuarial computations using the projected unit credit method. 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.
Convertible Notes
As discussed above, on May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, with a fixed interest rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. However, FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date. The 2026 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $1.48 billion, net of issuance costs.
Prior to the close of business on the business day immediately preceding February 1, 2026, the 2026 Convertible Notes will be convertible at the option of the holders only under the following conditions:
•During any calendar quarter, if the last reported sale price of FE’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;
•During the five consecutive business day period immediately after any 10 consecutive trading day period in which the trading price per $1,000 principal amount of the 2026 Convertible Notes for each trading day of such 10 trading day period was less than 98% of the product of the last reported sale price of FE’s common stock and the conversion rate on each such trading day; or
•Upon the occurrence of certain corporate events specified in the indenture governing the 2026 Convertible Notes.
On and after February 1, 2026, until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2026 Convertible Notes may convert all or any portion of their 2026 Convertible Notes at their option at any time at the conversion rate then in effect, irrespective of these conditions. FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash up to the aggregate principal amount of the 2026 Convertible Notes being converted and by paying cash or delivering shares of FE’s common stock (or a combination of each), at its election, of its conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted.
The conversion rate for the 2026 Convertible Notes will initially be 21.3620 shares of FE’s common stock per $1,000 principal amount of the 2026 Convertible Notes (equivalent to an initial conversion price of approximately $46.81 per share of FE’s common stock). The initial conversion price of the 2026 Convertible Notes represents a premium of approximately 20% over the last reported sale price of FE’s common stock on the New York Stock Exchange on May 1, 2023. The conversion rate and the corresponding conversion price will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.
If FE undergoes a fundamental change (as defined in the relevant indenture), subject to certain conditions, holders of the 2026 Convertible Notes may require FE to repurchase for cash all or any portion of their 2026 Convertible Notes at a repurchase price equal to 100% of the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date (as defined in the relevant indenture). In addition, if certain fundamental changes occur, FE may be required, in certain circumstances, to increase the conversion rate for any 2026 Convertible Notes converted in connection with such fundamental changes by a specified number of shares of its common stock.
Changes in Cash Position
As of December 31, 2024, FirstEnergy had $111 million of cash and cash equivalents and $43 million of restricted cash compared to $137 million of cash and cash equivalents and $42 million of restricted cash as of December 31, 2023, on the Consolidated Balance Sheets.
The following table summarizes the major classes of cash flow items:
For the Years Ended December 31,
(In millions) 2024 2023 2022
Net cash provided from operating activities $ 2,891 $ 1,387 $ 2,683
Net cash used for investing activities (4,350) (3,652) (3,076)
Net cash provided from (used for) financing activities 1,434 2,238 (912)
Net change in cash, cash equivalents and restricted cash (25) (27) (1,305)
Cash, cash equivalents, and restricted cash at beginning of period 179 206 1,511
Cash, cash equivalents, and restricted cash at end of period $ 154 $ 179 $ 206
Cash Flows From Operating Activities
FirstEnergy’s most significant sources of cash are derived from electric service provided by its operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve shopping customers, pension contributions and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.
Net cash provided from operating activities was $2,891 million during 2024, $1,387 million during 2023, and $2,683 million during 2022. The increase in cash from operating activities in 2024 from 2023 is primarily due to:
•Lower payments, primarily on generation energy purchases for certain customers, net of related customer receivable receipts;
•The return of cash collateral in 2024 that was previously posted with PJM, which was replaced with issuances of letters of credit;
•The absence of cash collateral returned to certain generation suppliers that serve shopping customers during 2023 that was previously received as a result of changes in power prices;
•$750 million cash contribution to qualified pension plan in the second quarter of 2023;
•Receipt of the derivative lawsuit settlement proceeds in the second quarter of 2024;
•Higher net transmission revenue collection based on the timing of formula rate collections; and
•Higher returns from distribution, integrated, and transmission capital investments.
The increase in cash provided from operating activities was partially offset by:
•Lower dividend distribution received by FEV from its equity investments in Global Holding;
•Higher payments associated with Pennsylvania gross receipts taxes; and
•Payment of the SEC civil penalty and OAG settlement in the third quarter of 2024.
FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2024, 2023 and 2022:
For the Years Ended December 31,
(In millions) 2024 2023 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations $ - $ (21) $ -
Loss (gain) on disposal, net of tax - 21 -
Cash Flows From Investing Activities
Cash used for investing activities in 2024 principally represented cash used for capital investments. The following table summarizes cash used for investing activities for the years ended 2024, 2023 and 2022:
For the Years Ended December 31,
Investing Activities 2024 2023 2022
(In millions)
Capital Investments:
Distribution Segment $ 1,130 $ 936 $ 925
Integrated Segment 1,542 1,212 998
Stand-Alone Transmission Segment 1,266 1,093 874
Corporate / Other 92 115 51
Asset removal costs 305 274 213
Other 15 22 15
$ 4,350 $ 3,652 $ 3,076
Cash used for investing activities during 2024 increased $698 million, compared to 2023, primarily due to higher planned capital investment spend.
Cash Flows From Financing Activities
Cash provided from (used for) financing activities was $1,434 million, $2,238 million, and $(912) million in 2024, 2023, and 2022, respectively. The following table summarizes financing activities for the years ended 2024, 2023, and 2022.
For the Years Ended December 31,
Financing Activities 2024 2023 2022
(In millions)
New Issues
Unsecured notes $ 2,100 $ 1,050 $ 300
Unsecured convertible notes - 1,500 -
FMBs - 600 400
2,100 3,150 700
Redemptions / Repayments
Unsecured notes (2,013) (494) (2,737)
FMBs (700) - (200)
Senior secured notes (47) (43) (68)
(2,760) (537) (3,005)
Proceeds from FET Equity Interest Sale (Note 1) 3,500 - -
Proceeds from 19.9% FET equity interest sale, net of transaction costs - - 2,348
Noncontrolling interest cash distributions (86) (72) (21)
Capital contributions from noncontrolling interest - - 9
Short-term borrowings, net (225) 675 100
Common stock dividend payments (970) (906) (891)
Debt issuance and redemption costs, and other (125) (72) (152)
$ 1,434 $ 2,238 $ (912)
During the year ended December 31, 2024, FirstEnergy had the following redemptions and issuances:
Company Type Redemption/Issuance Date Interest Rate Maturity Amount
(In millions) Description
Redemptions(1)
FE Unsecured Notes April, 2024 7.38% 2031 $463 FE redeemed all of its remaining $463 million of 2031 Notes including a premium of approximately $80 million ($63 million after-tax). In addition, FE recognized approximately $4 million ($3 million after-tax) of deferred cash flow hedge losses and $1 million in other unamortized debt costs and fees associated with the FE debt redemptions.
JCP&L Unsecured Notes April, 2024 4.70% 2024 $500 JCP&L redeemed unsecured notes that became due.
MP FMBs April, 2024 4.10% 2024 $400 MP redeemed FMBs that became due.
CEI FMBs August, 2024 5.50% 2024 $300 CEI redeemed FMBs that became due.
FE PA Unsecured Notes December, 2024 4.00% 2025 $250 On December 30, 2024, FE PA caused to be redeemed $250 million of 4.00% senior notes due 2025.
FE PA Unsecured Notes December, 2024 4.15% 2025 $200 On December 30, 2024, FE PA caused to be redeemed $200 million of 4.15% senior notes due 2025.
FET Unsecured Notes December, 2024 4.35% 2025 $600 On December 30, 2024, FET caused to be redeemed $600 million of 4.35% senior notes due 2025.
Issuances
ATSI Unsecured Notes March, 2024 5.63% 2034 $150 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MAIT Unsecured Notes May, 2024 5.94% 2034 $250 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
FET Unsecured Notes with registration rights September, 2024 4.55% 2030 $400 Proceeds were used to repay short-term borrowings, to redeem FET's $600 million 4.35% notes due 2025, to finance capital expenditures and for other general corporate purposes.
FET Unsecured Notes with registration rights September, 2024 5.00% 2035 $400 Proceeds were used to repay short-term borrowings, to redeem FET's $600 million 4.35% notes due 2025, to finance capital expenditures and for other general corporate purposes.
KATCo Unsecured Notes November, 2024 5.17% 2035 $200 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
JCP&L Unsecured Notes with registration rights December, 2024 5.10% 2035 $700 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
(1) Excludes principal payments on securitized bonds.
As noted above, on September 5, 2024, FET issued $400 million of unsecured senior notes due in 2030 and $400 million of unsecured senior notes due in 2035 in a private offering that included a registration rights agreement in which FET agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act. On October 8, 2024, FET filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on December 20, 2024. On January 24, 2025, FET completed an exchange offer of these senior notes for like principal amounts registered under the Securities Act.
As noted above, 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. JCP&L also agreed to file a shelf registration statement with the SEC to cover resales of the senior notes under certain circumstances. In the event that JCP&L's exchange offer is not completed or the shelf registration statement, if required, is not effective by the 366th day after December 5, 2024, or the effective shelf registration stops being effective for 60 days during any 12-month period, then additional interest will accrue on the coupon. Interest will accrue at a rate of 25 basis points for the first 90 days and an additional 25 basis points in the subsequent 90-day period, but not to exceed 50 basis points per year. However, if the additional interest is triggered, the interest rate will reset to the original notes rate once the registration statement is effective, or the shelf registration, if required, becomes effective. JCP&L plans to file a registration statement for the exchange offer before the end of the first quarter of 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.
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2024, outstanding guarantees and other assurances aggregated approximately $923 million, consisting of parental guarantees on behalf of its consolidated subsidiaries ($495 million) and other assurances ($428 million).
Collateral and Contingent-Related Features
In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
As of December 31, 2024, $170 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $29 million of net cash collateral as of December 31, 2024, from certain generation suppliers, and such amount is included in "Other current liabilities" on FirstEnergy's Consolidated Balance Sheets.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. See Note 15, "Commitments, Guarantees and Contingencies," of the Notes to Consolidated Financial Statements for more information.
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. As of December 31, 2024, FirstEnergy has a net asset of $7 million in non-hedge derivative contracts that are related to FTRs at certain of the Electric Companies. FTRs are subject to regulatory accounting and do not impact earnings.
Equity Price Risk
As of December 31, 2024, the FirstEnergy pension plan assets were allocated approximately as follows: 25% in public equity securities, 23% in fixed income securities, 4% in hedge funds, 1% in insurance-linked securities, (1)% in derivatives, 9% in real estate funds, 20% in private equity and debt funds and 19% in cash and short-term securities. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027, which based upon 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.
As of December 31, 2024, FirstEnergy's OPEB plan assets were allocated approximately as follows: 55% in equity securities, 25% in fixed income securities and 20% in cash and short-term securities. See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans.
During 2024, FirstEnergy's pension plan assets have lost approximately 0.4% as compared to an annual expected return on plan assets of 8.0%, and FirstEnergy's OPEB plan assets have gained approximately 13.4% as compared to an annual expected return on plan assets of 7.0%.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is largely mitigated as all long-term debt, with the exception of the 2021 Credit Facilities and the 2023 Credit Facilities, has fixed interest rates, as noted in the table below. However, FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities.
Comparison of Carrying Value to Fair Value as of December 31, 2024
Year of Maturity or Notice of Redemption 2025 2026 2027 2028 2029 There-after Total Fair Value
(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income $ 24 $ 20 $ 15 $ 2 $ 6 $ 203 $ 270 $ 270
Average interest rate 4.9 % 4.5 % 4.8 % 5.1 % 4.9 % 4.9 % 4.5 %
Liabilities:
Long-term Debt:
Fixed rate $ 973 $ 2,876 $ 2,003 $ 2,453 $ 1,064 $ 14,225 $ 23,594 $ 22,128
Average interest rate 3.3 % 4.0 % 3.8 % 3.8 % 4.0 % 4.6 % 4.3 %
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement (which occurred during the second quarter of 2023). A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs during the year, however, future years could be impacted by changes in the market.
On May 12, 2023, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan. The size of the voluntary contribution made on May 12, 2023, in relation to total pension assets triggered a remeasurement of the pension plan. FirstEnergy elected the practical expedient to remeasure pension plan assets and obligations as of April 30, 2023, which is the month-end closest to the date of the voluntary contribution.
FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. The discount rate used to measure pension obligations was 5.72% as of December 31, 2024 compared to 4.94% as of April 30, 2023 and 5.05% as of December 31, 2023. The discount rate used to measure OPEB obligations was 5.60% as of December 31, 2024 as compared to 4.97% as of December 31, 2023.
The 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates.
Economic Conditions
Economic conditions have stabilized across numerous material categories, but not all lead times have returned to pre-pandemic levels. Several key suppliers have seen improvements with capacity, but FirstEnergy continues to monitor the situation as demand increases across the industry, including due to data center usage. Inflationary pressures have moderated, which has improved the cost of materials, but certain categories have remained elevated. 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 FirstEnergy’s results of operations, cash flow and financial condition.
In February 2025, the new U.S. presidential administration announced the imposition of widespread and substantial tariffs on imports, with plans for additional tariffs to potentially be adopted in the future. Although certain of these tariffs were subsequently temporarily stayed, the situation is dynamic and subject to rapid change. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on FirstEnergy's results of operations, cash flow and financial condition.
CREDIT RISK
Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy's credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
OUTLOOK
INCOME TAXES
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 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. 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 expected taxable income in 2024. Due to certain limitations on NOL utilization enacted in the Tax Act, approximately $1.6 billion NOL will carry 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. Previously, in the fourth quarter of 2023, FirstEnergy recognized a charge to income tax expense of approximately $58 million as a true-up of the deferred tax liability associated with the deferred tax gain.
STATE REGULATION
Each of the 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.
The following table summarizes the key terms of state base rate orders in effect for the Electric Companies as of December 31, 2024:
Company Rates Effective For Customers Allowed Debt/Equity Allowed ROE
CEI May 2009 51%/ 49%
10.5%
FE PA(1)
January 2017 Settled(2)
Settled(2)
MP March 2024 Settled(2)
9.8%
JCP&L June 2024 48.1% / 51.9%
9.6%
OE January 2009 51% /49%
10.5%
PE (West Virginia) March 2024 Settled(2)
9.8%
PE (Maryland) October 2023 47% / 53%
9.5%
TE January 2009 51% / 49%
10.5%
(1) As further discussed below, new rates became effective for customers on January 1, 2025, and did not disclose allowed debt/equity and ROE rates.
(2) Commission-approved settlement agreements did not disclose allowed debt/equity and/or ROE rates.
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 previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally, at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, in accordance with the MDPSC directive, 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. On December 27, 2024, the MDPSC issued an order approving PE’s revised plan. PE recovers EmPOWER program costs with a return on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding. Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025, and 100% in 2026 and beyond. Notwithstanding the order to phase out the unamortized balances of EmPOWER investments, all previously unamortized costs for prior cycles were to be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the unamortized balances was extended through the end of 2030. On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years. On November 27, 2024, PE filed for approval of revised tariff pages reflecting an update of the PE tariff becoming effective in 2025, which included the requested analysis of alternative amortization methods. On December 18, 2024, the MDPSC approved the revised tariff pages permitting PE to continue to use its preferred amortization method. New legislation signed into law on May 9, 2024, and effective July 1, 2024, is expected to reduce
the return 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 and 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. The MDPSC and Maryland Office of People’s Counsel filed intents to participate. On November 15, 2024, the parties filed a joint motion to postpone the February 7, 2025 hearing date scheduled by the court and proposed a briefing schedule. The motion was granted on December 28, 2024. PE filed a Petitioner Memorandum on December 17, 2024. The MDPSC and Maryland Office of People’s Counsel filed a Response Memorandum on January 28, 2025. PE filed a Reply Memorandum on February 20, 2025. A hearing is scheduled for 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 base rate increase approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and became effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L was amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.
JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On May 22, 2024, the NJBPU approved JCP&L’s request for a six-month extension of the EE&C Plan I, to December 31, 2024. The budget for the extension period adds approximately $69 million to the original program cost and JCP&L will recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and had a proposed budget of approximately $964 million. EE&C Plan II, as filed, consisted of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. On October 30, 2024, the NJBPU approved the parties’ stipulation of settlement, wherein the parties agreed to a budget of approximately $817 million for EE&C Plan II, including $784 million of investments that will earn a return on equity of 9.6%, with an equity ratio of 52%, and be recovered over 10 years.
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. Orsted’s cancellation does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.
Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the 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.
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years. JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition.
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 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 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 has scheduled a technical conference for 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 compared to test period revenues, 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 compared to test period revenues 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. The Ohio Companies plan to respond and file supplemental testimony by March 24, 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 July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies proposed that phase two would be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan, which was approved by the PUCO on December 18, 2024 and implementation has since begun. The stipulation provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation, would be completed over a four-year budget period with estimated capital investments of approximately $421 million.
On 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 May 13, 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 May 13, 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 “Outlook - Other Legal Proceedings” below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.
PENNSYLVANIA
On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, 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, as further discussed below.
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 January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the next phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period beginning January 1, 2025 and ending December 31, 2029. The PPUC approved FE PA’s application on December 19, 2024, and implementation began in January 2025.
On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.
On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requested a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflected a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represented an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing included a proposal to change pension recovery from average cash contributions to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requested an enhanced ten-year vegetation management
program and recovery of certain incurred costs, including major storms, COVID-19, a program to convert streetlights to LEDs, and others. On September 13, 2024, FE PA and the active parties to the proceeding filed a joint settlement agreement requesting that the administrative law judges to approve FE PA’s requested distribution base rate case increase subject to the terms and conditions of the settlement, which included, among other things, an annual net revenue increase of $225 million. Other key components of the settlement agreement included recovery of costs incurred for storms and COVID-19, additional cost recovery of ongoing storm costs, inspection and maintenance of overhead lines and transformers, and rate case expenses, as well as an enhanced vegetation management program. On October 15, 2024, the administrative law judges issued a decision recommending that the PPUC approve, without modification, the September 13, 2024 settlement agreement. On November 21, 2024, the PPUC unanimously approved the settlement agreement without modification. New rates became effective on January 1, 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually.
On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, included the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 was to be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing, neither of which occurred. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024. MP and PE will file their next ENEC filing on or before September 1, 2025.
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. The first solar generation site went into service in January 2024 and the second solar generation site went into service in September 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.
On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE were seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and new depreciation rates became effective on April 1, 2024.
On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlements with slight non-material modifications with new rates going into effect on March 27, 2024.
Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset. See “Outlook - Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.
FERC REGULATORY MATTERS
Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
The following table summarizes the key terms of FERC rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2024:
Company Rates Effective Capital Structure Allowed ROE
ATSI January 2015 Actual (13-month average) 9.88%(1)
JCP&L
January 2020 Actual (13-month average) 10.20%
MP January 2021 Lower of Actual (13-month average) or 56% equity
10.45%
PE January 2021 Lower of Actual (13-month average) or 56% equity
10.45%
KATCo(2)
January 2021 Hypothetical 49.3% equity(3)
10.45%
MAIT July 2017 Lower of Actual (13-month average) or 60%
10.3%
TrAIL July 2008 Actual (year-end) 12.7%(2) / 11.7%(3)
(1) Reflects a 0.5% reduction to the 10.38% approved ROE due to the January 2025 Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership (see Transmission ROE Incentive: OCC v. ATSI, et al.)
(2) On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo
(3) Hypothetical capital structure will convert to an actual (13-month average) in January 2027
(4) TrAIL the Line and Black Oak Static Var Compensator
(5) All other projects
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy has recovered approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements as of December 31, 2024. These reclassifications also resulted in a reduction to the Stand-Alone Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Stand-Alone Transmission segment and on FirstEnergy’s Consolidated Statements of Income. 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 $100 million of certain corporate support costs allocated to distribution capital assets in Ohio.
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, the FERC Office of Enforcement issued a set of data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy responded. The FERC Office of Enforcement issued another set of data requests related to the same fuel consulting contract on January 13, 2025. Responses are due March 5, 2025. 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: OCC v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit. 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. FirstEnergy expects to pursue further appeal. During the fourth quarter of 2024, 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 at the Stand-Alone Transmission segment to reflect the expected refund owed to transmission customers back to February 24, 2022.
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.
Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.
On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.
Local Transmission Planning Complaint: Industrial Energy Consumers of America, et al. v. Avista Corporation, et al.
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 expects to participate in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. 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’s transmission capital investment strategy.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.
Clean Air Act
FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.
Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020,
the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the U.S. Supreme Court. Oral argument was heard on February 21, 2024. On June 27, 2024, the U.S. Supreme Court granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. 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.
Climate Change
In recent years, regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. 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). Our ability to achieve our GHG reduction goal is subject to our ability to make operational changes and is conditioned upon numerous risks, many of which are outside of our control. With respect to our coal-fired plants in West Virginia, which serve as the primary source of our Scope 1 emissions, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. FirstEnergy cannot currently estimate the financial impact of climate change policies, including the final SEC climate disclosure rules, which are currently stayed, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the
rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule 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 U.S. Supreme Court. On October 16, 2024, the U.S. Supreme Court 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. Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft. Martin and Harrison power stations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the 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 and will be reviewed by the U.S. Court of Appeals for the Eighth Circuit Court. On October 10, 2024, the Eighth Circuit denied the motions for stay. Depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of December 31, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. During the second quarter of 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 and corresponding increase to “Other operating expense” of $87 million at Corporate/Other for segment reporting. On February 3, 2025, AE Supply executed an environmental liability transfer agreement with a subsidiary of IDA Power, LLC, whereby AE Supply will transfer the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations. The agreement requires AE Supply to establish a $160 million escrow account that AE Supply will fund over five years. The escrow funding obligation will be secured by a surety bond, which will be guaranteed by FE. The transaction is expected to close before the end of the first quarter of 2025 and the derecognition of the ARO is not expected to have a material impact to FirstEnergy’s financial statements, however, no assurances of the closing of the transfer will be satisfied, including transfer of all required environmental permits.
On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. Depending on the outcome of appeals and the ultimate implementation of the final rule, compliance with these standards could require remedial actions, including removal of coal ash. See Note 8, “Asset Retirement Obligations,” above for a description of the $139 million increase to its ARO that FirstEnergy recorded during 2024 as a result of its analysis.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of December 31, 2024 based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $98 million have been accrued through December 31, 2024, of which approximately $69 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
United States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the U.S. Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District 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 United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 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 January 17, 2025, indictment. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information.
Legal Proceedings Relating to United States v. Larry Householder, et al.
On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers relating to the conduct described in the DPA. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. FirstEnergy cooperated fully with the SEC investigation, and on September 12, 2024, the SEC issued a settlement order that concluded and resolved the investigation in its entirety. Under the terms of the settlement, FE agreed to pay a civil penalty of $100 million and to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder, which was recognized as a loss contingency of $100 million in the second quarter of 2024 at Corporate/Other for segment reporting and paid on September 25, 2024.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understood that the OOCIC’s investigation was also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. On August 12, 2024, FirstEnergy entered into a settlement with the OAG's Office and the Summit County Prosecutor’s Office to resolve both the OOCIC investigation and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp., noted below. The settlement includes, among other things, a non-prosecution agreement and a payment of $19.5 million, which was recorded as a loss contingency in the second quarter of 2024 in FirstEnergy’s Consolidated Statements of Income at Corporate/Other for segment reporting and was paid on August 16, 2024.
In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing 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 of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order; the Sixth Circuit granted FE’s petition on November 16, 2023, and 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 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.
•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills included new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the case in light of the February 9, 2024, indictments against defendants in this action, which the court granted on March 14, 2024. As described above, FE reached a settlement with the OAG of this civil action and the OOCIC investigation, which resolves this civil action. FE recognized a loss contingency of $19.5 million in the second quarter of 2024, which was paid on August 16, 2024.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.
•Miller v. Anderson, et al. (N.D. Ohio); on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon the approval of the settlement by the S.D. Ohio, which was granted on May 17, 2024.
•Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); on September 1, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022, which was appealed by a purported FE stockholder on June 15, 2023. The U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. All appeal options were exhausted on May 16, 2024.
The above settlement included a series of corporate governance enhancements and a payment to FE of $180 million, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs, and a $7 million net return on deposited funds, which was received in the second quarter of 2024. The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.
The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 13, “Regulatory Matters.”
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can
be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations, and cash flows.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements. Additional information regarding the application of accounting policies is included in the Notes to Consolidated Financial Statements.
Loss Contingencies
FirstEnergy is involved in a number of investigations, litigation, regulatory audits, arbitration, mediation, and similar proceedings, including those surrounding HB 6. FirstEnergy regularly assesses its liabilities and contingencies in connection with asserted or potential matters and establishes reserves when appropriate. In the preparation of the financial statements, FirstEnergy makes judgments regarding the future outcome of contingent events based on currently available information and accrues liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. Circumstances change over time and actual results may vary significantly from estimates. See Note 14, “Regulatory Matters” and Note 15, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements for additional information.
Revenue Recognition
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from financial instruments, derivatives, late payment charges and other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the standard and accounted for under other existing GAAP.
Contracts with Customers
FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers for the Electric Companies is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.
Transmission revenues are primarily derived from forward-looking formula rates. Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.
FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. See Note 2, "Revenue," of the Notes to Consolidated Financial Statements for additional information.
Regulatory Accounting
FE's subsidiaries are subject to regulation that sets the prices (rates) the Electric Companies and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.
FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently
recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next year's recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 14, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.
Pension and OPEB Accounting
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. FirstEnergy provides a modest amount of noncontributory life insurance to retired employees in addition to optional contributory insurance to a closed group of retired employees. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
FirstEnergy pension and OPEB obligations are based on various assumptions in calculating these amounts. These assumptions include discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates, mortality rates, among others. Actual results that differ from the assumptions and changes in assumptions are recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement and affect obligations.
Discount Rate - In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. FirstEnergy utilizes a full yield curve approach in the estimation of the service and interest components of net periodic benefit costs for pension and other postretirement benefits by applying specific spot rates along the full yield curve to the relevant projected cash flows.
Expected Return on Plan Assets - The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets, the historical performance of risk-based and fixed income securities and other factors. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. The expected return on pension and OPEB assets for 2025 is 8.5% and 7.0%, respectively.
Mortality Rates - The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. The Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due to the ongoing impact of COVID-19 was utilized to determine the 2025 benefit cost and obligation as of December 31, 2024, for FirstEnergy's pension and OPEB plans. The MP-2021 scale was published in 2021 by the Society of Actuaries.
Health Care Trend Rates - Included in determining trend rate assumptions are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates.
Net Periodic Benefit Costs (Credits) - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement.
The following table reflects the pre-tax portion of pension and OPEB costs that were charged (credited) to expense, including pension and OPEB mark-to-market adjustments and special termination benefits, in the three years ended December 31, 2024, 2023, and 2022:
Net Periodic Benefit Costs (Credits) 2024 2023 2022
(In millions)
Pension $ 5 $ 57 $ (389)
OPEB (59) (40) (12)
Total $ (54) $ 17 $ (401)
The annual pre-tax pension and OPEB mark-to-market adjustment, (gains) or losses, for the years ended December 31, 2024, 2023, and 2022 were $22 million, $78 million and $(72) million, respectively.
FirstEnergy expects its 2025 pre-tax net periodic expense, including amounts capitalized and the impact of the 2025 lift-out transaction described below (excluding any potential mark-to-market adjustments) to be approximately $29 million based upon the following assumptions:
Assumption Pension OPEB
Effective rate for interest on benefit obligations 5.41 % 5.28 %
Effective rate for service costs 5.89 % 5.98 %
Effective rate for interest on service costs 5.66 % 5.88 %
Expected return on plan assets 8.50 % 7.00 %
Rate of compensation increase 4.30 % N/A
The approximate effects on 2025 pension and OPEB net periodic benefit costs and the 2024 benefit obligation from changes in key assumptions are as follows:
Approximate Effect on 2025 Net Periodic Benefit Costs from Changes in Key Assumptions
Assumption Change Pension OPEB Total
(In millions)
Discount rate Change by 0.25%(1)
$ 188 $ 7 $ 195
Expected return on plan assets Change by 0.25% $ 14 $ 1 $ 15
Health care trend rate Change by 1.0% N/A $ 9 $ 9
(1)Assumes a parallel shift in yield curve.
Approximate Effect on December 31, 2024 Benefit Obligation from Changes in Key Assumptions
Assumption Change Pension OPEB Total
(In millions)
Discount rate Change by 0.25%(1)
$ 203 $ 8 $ 211
Health care trend rate Change by 1.0% N/A $ 9 $ 9
(1)Assumes a parallel shift in yield curve.
See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional information.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes, reserve amounts for uncertain tax positions, and reporting of tax-related assets and liabilities such as the interpretation of tax laws and associated regulations. FirstEnergy is required to make judgments regarding the potential tax effects of various transactions and results of operations in order to estimate its obligations to taxing authorities.
Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FirstEnergy accounts for uncertainty in income taxes in its financial statements using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. FirstEnergy recognizes interest expense or income related to uncertain tax positions by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, or new regulations or guidance, forecasted results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities.
See Note 7, "Taxes," of the Notes to Consolidated Financial Statements for additional information on income taxes.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A relating to market risk is set forth in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements and supplementary data of FirstEnergy required in this item are set forth beginning on page 91.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of FirstEnergy Corp.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of FirstEnergy Corp. and its subsidiaries (the "Company") as of December 31, 2024 and 2023, and the related consolidated statements of income, of comprehensive income, of stockholders' equity and of cash flows for each of the three years in the period ended December 31, 2024, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Note 1 to the consolidated financial statements, the Company’s Regulated Distribution, Regulated Transmission and Integrated segments are subject to regulation that sets the prices (rates) the Company is permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. As of December 31, 2024, there were $617 million of regulatory assets and $995 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to accounting for the effects of rate regulation is a critical audit matter is a high degree of auditor effort in performing procedures and evaluating audit evidence related to the recovery of regulatory assets and the settlement of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the accounting for regulatory matters, including controls over the evaluation of the recoverability and settlement of existing regulatory assets and liabilities. These procedures also included, among others, (i) obtaining the Company’s correspondence with regulators, (ii) evaluating the reasonableness of management’s assessment regarding regulatory guidance, proceedings, and legislation and the related accounting implications, and (iii) testing, on a sample basis, the regulatory assets and liabilities by considering the provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Cleveland, Ohio
February 27, 2025
We have served as the Company’s auditor since 2002.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
(In millions, except per share amounts) 2024 2023 2022
REVENUES:
Distribution services and retail generation $ 10,976 $ 10,405 $ 9,916
Transmission 2,148 2,049 1,863
Other 348 416 680
Total revenues(1)
13,472 12,870 12,459
OPERATING EXPENSES:
Fuel 464 538 730
Purchased power 3,912 4,108 3,863
Other operating expenses 4,159 3,594 3,817
Provision for depreciation 1,581 1,461 1,375
Deferral of regulatory assets, net (231) (261) (365)
General taxes 1,212 1,164 1,129
Total operating expenses 11,097 10,604 10,549
OPERATING INCOME 2,375 2,266 1,910
OTHER INCOME (EXPENSE):
Debt redemption costs (Note 12)
(85) (36) (171)
Equity method investment earnings, net (Note 1) 58 175 168
Miscellaneous income, net 189 164 415
Pension and OPEB mark-to-market adjustments (22) (78) 72
Interest expense (1,144) (1,124) (1,039)
Capitalized financing costs 133 97 84
Total other expense (871) (802) (471)
INCOME BEFORE INCOME TAXES 1,504 1,464 1,439
INCOME TAXES 377 267 1,000
INCOME FROM CONTINUING OPERATIONS 1,127 1,197 439
Discontinued operations (Note 1)(2)
- (21) -
NET INCOME $ 1,127 $ 1,176 $ 439
Income attributable to noncontrolling interest (continuing operations) 149 74 33
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP. $ 978 $ 1,102 $ 406
AMOUNTS ATTRIBUTABLE TO FIRSTENERGY CORP.
Earnings from continuing operations $ 978 $ 1,123 $ 406
Earnings from discontinued operations - (21) -
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP. $ 978 $ 1,102 $ 406
EARNINGS PER SHARE ATTRIBUTABLE TO FIRSTENERGY CORP. (Note 3)
Basic - continuing operations $ 1.70 $ 1.96 $ 0.71
Basic - discontinued operations - (0.04) -
Basic $ 1.70 $ 1.92 $ 0.71
Diluted - continuing operations $ 1.70 $ 1.96 $ 0.71
Diluted - discontinued operations - (0.04) -
Diluted $ 1.70 $ 1.92 $ 0.71
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic 575 573 571
Diluted 577 574 572
(1) Includes excise and gross receipts tax collections of $429 million, $420 million and $406 million in 2024, 2023 and 2022, respectively.
(2) Consists of income taxes of $21 million in 2023.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31,
(In millions) 2024 2023 2022
NET INCOME $ 1,127 $ 1,176 $ 439
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs 1 (6) (9)
Amortized losses on derivative hedges 3 2 9
Other comprehensive income (loss) 4 (4) -
Income tax expense (benefits) on other comprehensive loss 1 (1) (1)
Other comprehensive income (loss), net of tax 3 (3) 1
COMPREHENSIVE INCOME $ 1,130 $ 1,173 $ 440
Comprehensive income attributable to noncontrolling interest 149 74 33
COMPREHENSIVE INCOME ATTRIBUTABLE TO FIRSTENERGY CORP. $ 981 $ 1,099 $ 407
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts) December 31,
2024 December 31,
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 111 $ 137
Restricted cash 43 42
Receivables-
Customers 1,585 1,382
Less - Allowance for uncollectible customer receivables 55 64
1,530 1,318
Other, net of allowance for uncollectible accounts of $6 in 2024 and $15 in 2023
303 266
Materials and supplies, at average cost 549 512
Prepaid taxes and other 240 293
2,776 2,568
PROPERTY, PLANT AND EQUIPMENT:
In service 52,896 50,107
Less - Accumulated provision for depreciation 14,548 13,811
38,348 36,296
Construction work in progress 2,754 2,116
41,102 38,412
INVESTMENTS AND OTHER NONCURRENT ASSETS:
Goodwill 5,618 5,618
Investments (Note 11)
652 663
Regulatory assets 617 369
Other 1,279 1,137
8,166 7,787
TOTAL ASSETS $ 52,044 $ 48,767
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Currently payable long-term debt $ 977 $ 1,250
Short-term borrowings 550 775
Accounts payable 1,575 1,362
Accrued interest 269 292
Accrued taxes 727 700
Accrued compensation and benefits 205 304
Dividends payable (Note 12)
245 235
Customer deposits 233 227
Other 216 241
4,997 5,386
NONCURRENT LIABILITIES:
Long-term debt and other long-term obligations 22,496 22,885
Accumulated deferred income taxes 5,613 4,530
Retirement benefits 1,698 1,663
Regulatory liabilities 995 1,214
Other 2,525 2,173
33,327 32,465
TOTAL LIABILITIES 38,324 37,851
EQUITY:
Common stockholders' equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 576,612,245 and 574,335,396 shares outstanding as of December 31, 2024 and 2023, respectively
58 57
Other paid-in capital 12,368 10,494
Accumulated other comprehensive loss (14) (17)
Retained earnings (accumulated deficit) 43 (97)
Total common stockholders' equity 12,455 10,437
Noncontrolling interest 1,265 479
TOTAL EQUITY 13,720 10,916
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 15)
TOTAL LIABILITIES AND EQUITY $ 52,044 $ 48,767
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Common Stock OPIC AOCI Retained Earnings (Accumulated Deficit) Total Common Stockholders' Equity
(In millions) Shares Amount NCI Total Equity
Balance, January 1, 2022 570 $ 57 $ 10,238 $ (15) $ (1,605) $ 8,675 $ - $ 8,675
Net income - - - - 406 406 33 439
Other comprehensive income, net of tax - - - 1 - 1 - 1
Cash dividends declared on common stock(1)
- - (892) - - (892) - (892)
Stock Investment Plan and share-based benefit plans 2 - 98 - - 98 - 98
19.9% FET equity interest sale, net of transaction costs (Note 1)
- - 1,887 - - 1,887 451 2,338
Noncontrolling interest distributions declared - - - - - - (21) (21)
Capital contribution from FET equity interest - - - - - - 9 9
Consolidated tax benefit allocation - - (5) - - (5) 5 -
Other - - (4) - - (4) - (4)
Balance, December 31, 2022 572 $ 57 $ 11,322 $ (14) $ (1,199) $ 10,166 $ 477 $ 10,643
Net income - - - - 1,102 1,102 74 1,176
Other comprehensive loss, net of tax - - - (3) - (3) - (3)
Cash dividends declared on common stock(1)
- - (917) - - (917) - (917)
Stock Investment Plan and share-based benefit plans 2 - 89 - - 89 - 89
Noncontrolling interest distributions declared - - - - - - (72) (72)
Balance, December 31, 2023 574 $ 57 $ 10,494 $ (17) $ (97) $ 10,437 $ 479 $ 10,916
Net income - - - - 978 978 149 1,127
Other comprehensive income, net of tax - - - 3 - 3 - 3
Cash dividends declared on common stock(1)
- - (141) - (838) (979) - (979)
Stock Investment Plan and share-based benefit plans 3 1 73 - - 74 - 74
FET Equity Interest Sale (Note 1) - - 1,934 - - 1,934 731 2,665
Noncontrolling interest distributions declared - - - - - - (86) (86)
Other 8 8 (8) -
Balance, December 31, 2024 577 $ 58 $ 12,368 $ (14) $ 43 $ 12,455 $ 1,265 $ 13,720
(1) Dividends declared for each share of common stock totaled $1.70, $1.60 and $1.56 during 2024, 2023 and 2022, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
(In millions) 2024 2023 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 1,127 $ 1,176 $ 439
Adjustments to reconcile net income to net cash from operating activities-
Depreciation, amortization and impairments 1,588 1,280 1,317
Charges associated with change in ARO (Note 10)
200 - -
Employee benefit costs, net (32) (9) (279)
Pension and OPEB mark-to-market adjustments 22 78 (72)
Deferred income taxes and investment tax credits, net 316 252 989
Transmission revenue collections, net 113 (180) 79
Pension trust contribution - (750) -
Loss (gain) on disposal, net of tax (Note 17)
- 21 -
Changes in current assets and liabilities-
Receivables (249) (13) (292)
Materials and supplies (37) (91) (161)
Prepaid taxes and other current assets (33) (43) (28)
Accounts payable 124 (141) 560
Accrued taxes (126) 32 22
Accrued interest (23) 38 (29)
Other current liabilities (141) 41 21
Cash collateral, net 90 (218) 111
Employee benefit plan funding and related payments (59) (50) (49)
Other 11 (36) 55
Net cash provided from operating activities 2,891 1,387 2,683
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital investments (4,030) (3,356) (2,848)
Sales of investment securities held in trusts 121 38 48
Purchases of investment securities held in trusts (134) (50) (59)
Asset removal costs (305) (274) (213)
Other (2) (10) (4)
Net cash used for investing activities (4,350) (3,652) (3,076)
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt 2,100 3,150 700
Short-term borrowings, net - 675 100
Redemptions and repayments-
Long-term debt (2,760) (537) (3,005)
Short-term borrowings, net (225) - -
Proceeds from FET Equity Interest Sale (Note 1) 3,500 - -
Proceeds from 19.9% FET equity interest sale, net of transaction costs
- - 2,348
Noncontrolling interest cash distributions (86) (72) (21)
Capital contributions from noncontrolling interest - - 9
Common stock dividend payments (970) (906) (891)
Debt issuance and redemption costs, and other (125) (72) (152)
Net cash provided from (used for) financing activities 1,434 2,238 (912)
Net change in cash, cash equivalents and restricted cash (25) (27) (1,305)
Cash, cash equivalents, and restricted cash at beginning of period 179 206 1,511
Cash, cash equivalents, and restricted cash at end of period $ 154 $ 179 $ 206
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year-
Interest (net of amounts capitalized) $ 1,062 $ 1,002 $ 1,021
Income taxes, net of refunds $ 161 $ 58 $ 21
Significant non-cash transactions:
Accrued capital investments $ 315 $ 252 $ 207
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note
Number
Page
Number
Organization and Basis of Presentation
2 Revenue 103
3 Earnings Per Share 107
4 Accumulated Other Comprehensive Income 109
5 Pension and Other Postemployment Benefits
6 Stock-Based Compensation Plans 109
7 Taxes 112
8 Leases 115
9 Variable Interest Entities 118
10 Asset Retirement Obligations 120
11 Fair Value Measurements 121
12 Capitalization 124
13 Short-Term Borrowings and Bank Lines of Credit 128
14 Regulatory Matters 129
15 Commitments, Guarantees and Contingencies 139
16 Segment Information 145
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.
FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries as of December 31, 2024: 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.
In addition, FE holds all of the outstanding equity of other direct subsidiaries including FEV, which currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations.
On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.
Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.
FESC provides legal, financial and other corporate support services at cost, in accordance with its cost allocation manual, to affiliated FirstEnergy companies. FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries for services received from FESC either through direct billing or through an allocation process. Allocated costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. Intercompany transactions are generally settled under commercial terms within thirty days.
FE and its subsidiaries are principally involved in the transmission, distribution, and generation of electricity. FirstEnergy’s electric operating companies comprise one of the nation’s largest investor-owned electric systems, serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include more than 24,000 miles of transmission lines and two regional transmission operation centers. As of December 31, 2024, MP and AGC control 3,604 MWs of total capacity.
The accompanying consolidated financial statements have been prepared in accordance with GAAP and the rules and regulations of the SEC. FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. As further discussed below, FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.
Certain prior year amounts have been reclassified to conform to the current year presentation. During the first quarter of 2024, FirstEnergy’s segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. The modification to the segments resulted in a reallocation of goodwill between the segments based on the relative fair value of the reporting units, as described further below. Disclosures for FirstEnergy's reportable operating segments for 2023 and
2022 have been reclassified to conform to the current presentation reflecting the new reportable segments. In addition, on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and for comparability, prior year results in the Stand-Alone Transmission segment reflect the earnings and results of those WP transmission assets.
Economic Conditions
Economic conditions have stabilized across numerous material categories, but not all lead times have returned to pre-pandemic levels. Several key suppliers have seen improvements with capacity, but FirstEnergy continues to monitor the situation as demand increases across the industry, including due to data center usage. Inflationary pressures have moderated, which has improved the cost of materials, but certain categories have remained elevated. 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 FirstEnergy’s results of operations, cash flow and financial condition.
In February 2025, the new U.S. presidential administration announced the imposition of widespread and substantial tariffs on imports, with plans for additional tariffs to potentially be adopted in the future. Although certain of these tariffs were subsequently temporarily stayed, the situation is dynamic and subject to rapid change. The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on FirstEnergy's results of operations, cash flow and financial condition.
Facility Optimization
FirstEnergy continues implementing its facility optimization plans, which will result in exiting the general office in Akron, Ohio, and other corporate facilities in Greensburg, Pennsylvania, and Morristown, New Jersey. In December 2023, FirstEnergy purchased the general office building with the intention to sell it in the future. During the third quarter of 2024, the Akron general office building was classified as held-for-sale. Upon classification as held-for-sale, FirstEnergy recognized a $62 million pre-tax impairment charge within “Other operating expenses” on the Consolidated Statements of Income. Of the $62 million, $17 million is included with Integrated, $31 million is included within Distribution, $11 million is included within Stand-Alone Transmission and $3 million at Corporate/Other for segment reporting. The remaining carrying value of the held-for-sale asset is immaterial, and therefore has not been presented separately on the Consolidated Balance Sheets. The corporate headquarters will remain in Akron, Ohio, moving to FirstEnergy’s campus located in west Akron, Ohio, and FirstEnergy continues to explore real estate options and relocation opportunities for the other corporate facilities. As FirstEnergy continues to transform the business and implement initiatives to reduce costs, including the facility optimization plan, the impact of such actions may result in future impairments or other charges that may be significant. The aim of these combined efforts will be to help build a stronger, more sustainable company for the near and long term.
Sale of Equity Interests in FirstEnergy Transmission, LLC
On May 31, 2022, Brookfield acquired 19.9% of the issued and outstanding membership interests of FET. On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes. Interest income associated with the promissory notes was $24 million for the year ended December 31, 2024 and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET. The difference between the purchase price, net of transaction costs and taxes of approximately $32 million and $803 million, respectively, and the carrying value of the NCI of $731 million, was recorded as an increase to OPIC by $1.9 billion.
Pursuant to the terms of the FET P&SA II, in connection with the closing, Brookfield, FET and FE entered into the A&R FET LLC Agreement, which amended and restated in its entirety the Third Amended and Restated Limited Liability Company Agreement of FET. The A&R FET LLC Agreement, among other things, provides for the governance, exit, capital and distribution, and other arrangements for FET from and following the closing. Under the A&R FET LLC Agreement, as of the closing, the FET Board consists of five directors, two of whom are appointed by Brookfield and three of whom are appointed by FE.
Discontinued operations
On February 27, 2020, the FES Debtors emerged from bankruptcy and were deconsolidated from FirstEnergy’s consolidated federal income tax group. The bankruptcy, emergence and deconsolidation resulted in FirstEnergy recognizing certain income tax benefits and charges, which were classified as discontinued operations. During the third quarter of 2023, FirstEnergy recognized a $21 million tax-effected charge to income tax expense as a result of identifying an out of period adjustment related to the allocation of certain deferred income tax liabilities associated with the FES Debtors and their tax return deconsolidation in 2020. This adjustment was immaterial to the 2023 and prior period financial statements.
Discontinued operations are reflected at Corporate/Other for segment reporting and within “Discontinued Operations” on the Consolidated Statements of Income and Comprehensive Income and “Loss on disposal, net of tax” on the Consolidated Statements of Cash Flow.
ACCOUNTING FOR THE EFFECTS OF REGULATION
FirstEnergy’s operating segments are subject to regulation that sets the prices (rates) the Electric Companies and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.
FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 14, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.
The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2024 and 2023, and the changes during the year 2024:
As of December 31,
Net Regulatory Assets (Liabilities) by Source 2024 2023 Change
(In millions)
Customer payables for future income taxes $ (2,234) $ (2,382) $ 148
Spent nuclear fuel disposal costs (72) (83) 11
Asset removal costs (681) (652) (29)
Deferred transmission costs 190 286 (96)
Deferred generation costs 481 572 (91)
Deferred distribution costs 287 247 40
Storm-related costs 1,015 799 216
Energy efficiency program costs 349 198 151
New Jersey societal benefit costs 87 79 8
Vegetation management 125 102 23
Other 75 (11) 86
Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (378) $ (845) $ 467
The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2024 and 2023, of which approximately $698 million and $371 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:
Regulatory Assets by Source Not Earning a As of December 31,
Current Return 2024 2023 Change
(In millions)
Deferred transmission costs $ 8 $ 6 $ 2
Deferred generation costs 314 432 (118)
Deferred distribution costs 153 68 85
Storm-related costs 694 602 92
Vegetation management 16 21 (5)
Other 58 68 (10)
Regulatory Assets Not Earning a Current Return $ 1,243 $ 1,197 $ 46
DERIVATIVES
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.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.
EQUITY METHOD INVESTMENTS
Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and reflected in "Investments". The percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income and reflected in “Other Income (Expense)”. Equity method investments are assessed for impairment annually or whenever events and changes in circumstances indicate that the carrying amount of the investment may not be recoverable. If the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment.
Equity method investments included within "Investments" on the Consolidated Balance Sheets were $84 million and $104 million as of December 31, 2024 and 2023, respectively.
Global Holdings - FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales primarily focused on international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. For the years ended December 31, 2024, 2023 and 2022, pre-tax equity earnings, excluding impairments, related to FEV’s ownership in Global Holding was $72 million, $175 million and $168 million, respectively. FEV’s pre-tax equity earnings and investment in Global Holding are included in Corporate/Other for segment reporting.
Due to FirstEnergy's actions to exit from FEV’s equity method investment in Global Holdings, a $13 million (pre-tax) impairment charge was recognized in the fourth quarter of 2024 and is included within "Equity method investment earnings, net” on the Consolidated Statements of Income and within Corporate/Other for segment reporting.
As of December 31, 2024 and 2023, the carrying value of the equity method investment was $45 million and $66 million, respectively. During 2024 and 2023, FEV received cash dividends from Global Holding totaling $80 million and $165 million, respectively, which were classified with “Cash from Operating Activities” on FirstEnergy’s Consolidated Statements of Cash Flow.
PATH WV - PATH, was a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting.
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. As of December 31, 2024 and 2023, the carrying
value of the equity method investment was $17 million, which is expected to be recovered through a distribution. FirstEnergy's pre-tax equity earnings in PATH-WV were immaterial for the years ended December 31, 2024, 2023 and 2022.
GOODWILL
In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.
In accordance with GAAP, the modification to the segments in the first quarter of 2024 resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its CODM) to regularly assess performance of the business and allocate resources.
The fair values of the reporting units were calculated using a discounted cash flow analysis. Key assumptions incorporated in the discounted cash flow analysis included discount rates, growth rates, projected operating income, changes in working capital, projected capital investments, and terminal multiples. The discounted cash flow analysis was also utilized to complete an impairment assessment before and after the segment change, with no impairment of goodwill indicated.
As of July 31, 2024, FirstEnergy performed a qualitative assessment of its reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment included: growth rates, interest rates, expected investments, utility sector market performance, regulatory and legal developments, and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary.
FirstEnergy's reporting units are consistent with its reportable segments and consist of Distribution, Integrated and Stand-Alone Transmission. The following table presents goodwill by reporting unit as of December 31, 2024 and 2023:
(In millions) Distribution Segment Integrated Segment Stand-Alone Transmission Segment FirstEnergy Consolidated
Goodwill $ 3,222 $ 1,953 $ 443 $ 5,618
INVENTORY
Materials and supplies inventory primarily includes fuel inventory, the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory as well as emission allowances. Materials charged to inventory are at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory consists primarily of coal and reagents that are consumed at MP's generation plants, and is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed.
Emission allowances are accounted for as inventory at cost when purchased. FirstEnergy’s emission allowance compliance obligation, principally associated with MP's generation plant operations, is accrued to fuel expense at a weighted average cost based on each month’s emissions. When emission allowances are submitted to the EPA, inventory and the compliance obligation are reduced. Due to the ENEC, fuel, emission allowances and other fuel-related expenses have no material impact on current period earnings.
NONCONTROLLING INTEREST
FirstEnergy maintains a controlling financial interest in certain less than wholly owned subsidiaries. As a result, FirstEnergy presents the third-party investors’ ownership portion of FirstEnergy's net income, net assets and comprehensive income as noncontrolling interest. Noncontrolling interest is included as a component of equity on the Consolidated Balance Sheets.
On May 31, 2022, Brookfield and the Brookfield Guarantors acquired 19.9% of the issued and outstanding membership interests of FET. The difference between the cash consideration received, net of transaction costs of approximately $37 million, and the carrying value of the noncontrolling interest of $451 million was recorded as an increase to OPIC. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the transaction and remains in the Stand-Alone Transmission segment.
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The difference between the purchase price, net of transaction costs and deferred taxes of approximately $32 million and $803 million respectively, and the carrying value of the NCI of $731 million, was recorded as an increase to OPIC by $1.9 billion during 2024.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and financing costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred.
Property, plant and equipment balances by segment as of December 31, 2024 and 2023, were as follows:
December 31, 2024
Segment In Service(1)
Accum. Depr.(2)
Net Plant CWIP Total Average Service Life
(In millions) (years)
Distribution $ 21,245 $ (7,338) $ 13,907 $ 618 $ 14,525 5 - 80
Integrated 17,080 (3,943) 13,137 1,076 14,213 5 - 100
Stand-Alone Transmission 13,509 (2,660) 10,849 986 11,835 5 - 85
Corporate/Other 1,062 (607) 455 74 529 3 - 63
Total Property, Plant and Equipment $ 52,896 $ (14,548) $ 38,348 $ 2,754 $ 41,102
December 31, 2023
Segment In Service(1)
Accum. Depr.(2)
Net Plant CWIP Total Average Service Life
(In millions) (years)
Distribution $ 20,423 $ (7,008) $ 13,415 $ 417 $ 13,832 5 - 80
Integrated 16,180 (3,748) 12,432 823 13,255 5 - 100
Stand-Alone Transmission 12,388 (2,461) 9,927 828 10,755 5 - 85
Corporate/Other 1,116 (594) 522 48 570 3 - 63
Total Property, Plant and Equipment $ 50,107 $ (13,811) $ 36,296 $ 2,116 $ 38,412
(1) Includes finance leases of $46 million and $68 million as of December 31, 2024 and 2023, respectively.
(2) Includes finance lease accumulated amortization of $14 million and $33 million as of December 31, 2024 and 2023, respectively.
Integrated has approximately $2.3 billion of total regulated generation property, plant and equipment as of December 31, 2024.
FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were approximately 2.9%, 2.8% and 2.7% in 2024, 2023 and 2022, respectively.
For the years ended December 31, 2024, 2023 and 2022, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $60 million, $44 million and $56 million, respectively, of allowance for equity funds used during construction and $73 million, $53 million and $28 million, respectively, of capitalized interest.
Asset Impairments
FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value.
Jointly Owned Plants
AGC owns an undivided 16.25% interest (487 MWs) in the 3,003 MW Bath County pumped-storage, hydroelectric station in
Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Total property, plant and equipment includes $142 million representing AGC's share in this facility as of December 31, 2024. AGC is obligated to pay its share of the costs of this jointly owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in operating expenses on FirstEnergy's Consolidated Statements of Income. AGC provides the generation capacity from this facility to its owner, MP, which is recovered through the ENEC.
NEW ACCOUNTING PRONOUNCEMENTS
Recently Adopted Pronouncements
ASU 2022-03, "Fair Value Measurements of Equity Securities Subject to Contractual Sale Restrictions " (Issued in June 2022): ASU 2022-03 clarifies current guidance in Topic 820, Fair Value Measurement, when measuring the fair value of an equity security subject to contractual restrictions that prohibit the sale of an equity security, and introduces new disclosure requirements for those equity securities subject to contractual restrictions. The adoption of this ASU did not have a material impact on the financial statements.
ASU 2023-07, "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures " (Issued in November 2023): ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contains other disclosure requirements. Disclosure requirements within ASU 2023-07 include disclosing significant segment expenses by reportable segment if they are regularly provided to the CODM and included in each reported measure of segment profit or loss. A public entity is also required to disclose the title and position of the individual(s) identified as the CODM as well as an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Disclosures are required on both an annual and an interim basis. The segment disclosures within have been updated to reflect the requirements of ASU 2023-07.
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.
ASU 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 FirstEnergy, the guidance will be effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The amendments within ASU 2023-09 are to be applied on a prospective basis, with retrospective application permitted.
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 FirstEnergy 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.
2. REVENUE
FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the standard and accounted for under other existing GAAP.
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.
•Distribution Segment, which consists of the Ohio Companies and FE PA;
•Integrated Segment, which consists of MP, PE and JCP&L; and
•Stand-Alone Transmission Segment, which consists of FE's ownership in FET and KATCo.
The Electric Companies distribute electricity through FirstEnergy’s utility operating companies and also controls 3,604 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. Each of the Electric Companies earns
revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Electric Companies are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 14, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.
The following represents a disaggregation of revenue from contracts with customers for the years ended December 31, 2024, 2023 and 2022:
For the Years Ended December 31,
(In millions) 2024 2023 2022
Distribution
Retail generation and distribution services(1)
Residential $ 4,514 $ 4,344 $ 3,954
Commercial 1,522 1,528 1,432
Industrial 588 726 806
Other 73 72 56
Wholesale 6 20 19
Other revenue from contracts with customers (2)
80 89 86
Total revenues from contracts with customers 6,783 6,779 6,353
Other revenue unrelated to contracts with customers (3)
80 75 72
Total Distribution $ 6,863 $ 6,854 $ 6,425
Integrated
Retail generation and distribution services
Residential $ 2,528 $ 2,137 $ 2,121
Commercial 1,142 1,023 1,016
Industrial 577 545 505
Other 32 30 26
Wholesale 146 208 475
Transmission 380 318 282
Other revenue from contracts with customers(4)
19 24 17
Total revenues from contracts with customers 4,824 4,285 4,442
ARP (4)
10 - -
Other revenue unrelated to contracts with customers(3)
42 35 28
Total Integrated $ 4,876 $ 4,320 $ 4,470
Stand-Alone Transmission
ATSI $ 980 $ 967 $ 911
TrAIL 269 279 270
MAIT 436 394 340
KATCo 85 89 59
Other (2) 2 1
Total revenues from contracts with customers 1,768 1,731 1,581
Other revenue unrelated to contracts with customers 19 17 16
Total Stand-Alone Transmission $ 1,787 $ 1,748 $ 1,597
Corporate/Other, Eliminations and Reconciling Adjustments (5)
Wholesale $ 9 $ 11 $ 27
Eliminations and reconciling adjustments (63) (63) (60)
Total Corporate/Other, Eliminations and Reconciling Adjustments $ (54) $ (52) $ (33)
FirstEnergy Total Revenues $ 13,472 $ 12,870 $ 12,459
(1) Includes approximately $58 million as of December 31, 2022 of customer refunds associated with the Ohio Stipulation that became effective in December 2021.
(2) Primarily includes amounts collected from customers to administer and repay securitization bonds and pole attachment revenue.
(3) Primarily includes late payment charges and revenue from FTRs.
(4) Related to lost distribution revenues associated with energy efficiency in New Jersey.
(5) Includes eliminations and reconciling adjustments of inter-segment revenues.
Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Electric Companies have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, FE PA, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer.
Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Electric Companies may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and Incremental Auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur.
The Electric Companies’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Electric Companies accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days.
ASC 606 excludes industry-specific accounting guidance for recognizing revenue from Alternative Revenue Programs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenues from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers.
Transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's Electric Companies (JCP&L, MP and PE) transmits electricity from generation sources to distribution facilities. Transmission revenues are derived primarily from forward-looking formula rates. See Note 14, “Regulatory Matters,” for additional information. Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on rate base and actual costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.
FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.
RECEIVABLES
Receivables from contracts with customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Electric Companies. Billed and unbilled customer receivables as of December 31, 2024 and 2023, are included below.
As of December 31,
Customer Receivables 2024 2023
(In millions)
Billed(1)
$ 867 $ 717
Unbilled 718 665
1,585 1,382
Less: Uncollectible Reserve 55 64
Total Customer Receivables $ 1,530 $ 1,318
(1) Includes approximately $284 million and $288 million as of December 31, 2024 and 2023, respectively, that are past due by greater than 30 days.
The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible customer receivables should be further adjusted in accordance with the accounting guidance for credit losses.
FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Electric Companies are able to utilize to ensure payment. FirstEnergy’s uncollectible risk on PJM receivables, resulting from transmission and wholesale sales, is minimal due to the nature of PJM’s settlement process and as a result there is no current allowance for doubtful accounts.
Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2024, 2023 and 2022 are as follows:
(In millions) 2024 2023 2022
Customer Receivables:
Beginning of year balance $ 64 $ 137 $ 159
Charged to income(1)
73 8 59
Charged to other accounts(2)
39 34 62
Write-offs (121) (115) (143)
End of year balance $ 55 $ 64 $ 137
Other Receivables:
Beginning of year balance $ 15 $ 11 $ 10
Charged to income 1 7 4
Charged to other accounts(2)
(5) (1) 4
Write-offs (5) (2) (7)
End of year balance $ 6 $ 15 $ 11
(1) Customer receivable amounts charged (credited) to income for the years ended December 31, 2024, 2023, and 2022, include approximately $17 million, $(15) million, and $11 million, respectively, deferred for future recovery (refund).
(2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts.
3. EARNINGS PER SHARE OF COMMON STOCK
EPS is calculated by dividing earnings attributable to FE by the weighted average number of common shares outstanding.
Basic EPS is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.
Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible securities. The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for
the period. The dilutive effect of the 2026 Convertible Notes, as further discussed in Note 12, "Capitalization" under Long-term debt and other long-term obligations, is computed using the if-converted method.
The following table reconciles basic and diluted EPS attributable to FE:
For the Years Ended December 31,
Reconciliation of Basic and Diluted EPS of Common Stock 2024 2023 2022
(In millions, except per share amounts)
Earnings Attributable to FE - continuing operations $ 978 $ 1,123 $ 406
Earnings Attributable to FE - discontinued operations, net of tax - (21) -
Earnings Attributable to FE $ 978 $ 1,102 $ 406
Share Count information:
Weighted average number of basic shares outstanding 575 573 571
Assumed exercise of dilutive share-based awards 2 1 1
Weighted average number of diluted shares outstanding 577 574 572
EPS Attributable to FE:
Income from continuing operations, basic $ 1.70 $ 1.96 $ 0.71
Discontinued operations, basic - (0.04) -
Basic EPS $ 1.70 $ 1.92 $ 0.71
Income from continuing operations, diluted $ 1.70 $ 1.96 $ 0.71
Discontinued operations, diluted - (0.04) -
Diluted EPS $ 1.70 $ 1.92 $ 0.71
For the years ended December 31, 2024, 2023 and 2022, there was no material amount of shares excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.
The dilutive effect of the 2026 Convertible Notes is limited to the conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted. For the year ended December 31, 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. See Note 12, "Capitalization" for additional details on the 2026 Convertible Notes that were issued during the second quarter of 2023.
4. ACCUMULATED OTHER COMPREHENSIVE INCOME
The changes in AOCI for the years ended December 31, 2024, 2023 and 2022, for FirstEnergy are shown in the following table:
2024 2023 2022
(In millions)
Gains & Losses on Cash Flow Hedges(1)
AOCI Balance, January 1, $ 2 $ - $ (7)
Amounts reclassified from AOCI 3 2 9
Income tax on other comprehensive income 1 - 2
Other comprehensive income, net of tax 2 2 7
AOCI Balance, December 31, $ 4 $ 2 $ -
Defined Benefit Pension & OPEB Plans(2)(3)
AOCI Balance, January 1, $ (19) $ (14) $ (8)
Amounts reclassified from AOCI 1 (6) (9)
Income tax benefits on other comprehensive loss - (1) (3)
Other comprehensive loss, net of tax 1 (5) (6)
AOCI Balance, December 31, $ (18) $ (19) $ (14)
Total FirstEnergy Corp. AOCI
AOCI Balance, January 1, $ (17) $ (14) $ (15)
Other comprehensive income (loss), net of tax 3 (3) 1
AOCI Balance, December 31, $ (14) $ (17) $ (14)
(1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. Amounts reclassified from AOCI affects Interest expense line item in Consolidated Statements of Income.
(2) Amortization of prior service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Postemployment Benefits," for additional details.
(3) Income tax (benefits) on other comprehensive income (loss) affects Income taxes line item in Consolidated Statements of Income.
5. PENSION AND OTHER POSTEMPLOYMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy credits amounts to eligible employee notional cash-balance accounts based on a pay credit and an interest credit.
In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance to a closed group of retired employees. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
FirstEnergy’s pension funding policy is based on actuarial computations using the projected unit credit method. 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.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans or whenever a plan is determined to qualify for a remeasurement. The fair value of the plan assets represents the actual market value as of the measurement date.
In December 2023, FirstEnergy, executed a lift-out transaction with Banner Life Insurance Company and Reinsurance Group of America that transferred approximately $683 million of plan assets and $719 million of plan obligations, associated with approximately 1,900 former competitive generation employees, who will assume future and full responsibility to fund and
administer their benefit payments. There was no change to the pension benefits for any participants as a result of the transfer. The transaction was funded by pension plan assets and resulted in a pre-tax gain of approximately $36 million, which was included in the fourth quarter 2023 pension and OPEB mark-to-market adjustment charge.
Additionally, in January 2025, FirstEnergy executed a lift-out transaction with MetLife, that 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. Similar to the lift-out in 2023, 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.
Actuarial Assumptions Pension OPEB
2024 2023 (2)
2022 2024 2023 (2)
Assumptions Related to Benefit Obligations:
Discount rate 5.72 % 5.05 % 5.23 % 5.60 % 4.97 % 5.16 %
Rate of compensation increase 4.30 % 4.30 % 4.30 % N/A N/A N/A
Cash balance weighted average interest crediting rate 4.37 % 4.94 % 4.04 % N/A N/A N/A
Assumptions Related to Benefit Costs:(1)
Effective rate for interest on benefit obligations 4.92 % 5.10% / 4.80%
2.44 % 4.88 % 5.06 % 2.18 %
Effective rate for service costs 5.17 % 5.34% / 5.11%
3.28 % 5.23 % 5.41 % 3.41 %
Effective rate for interest on service costs 5.05 % 5.22% / 4.94%
2.96 % 5.16 % 5.33 % 3.24 %
Expected return on plan assets 8.00 % 8.00 % 7.50 % 7.00 % 7.00 % 7.50 %
Rate of compensation increase 4.30 % 4.30 % 4.10 % N/A N/A N/A
Assumed Health Care Cost Trend Rates:
Health care cost trend rate assumed (pre/post-Medicare) N/A N/A N/A 7.00%-
6.00%
7.00%-
6.50%
6.00%-
5.50%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) N/A N/A N/A 4.50 % 4.50 % 4.50 %
Year that the rate reaches the ultimate trend rate N/A N/A N/A 2035 2033 2029
(1) Excludes impact of pension and OPEB mark-to-market adjustments.
(2) As a result of the interim plan remeasurement during 2023, different rates were in effect from January 1, 2023, through April 30, 2023 compared to May 1, 2023 through December 31, 2023.
Discount Rate - The discount rate is determined using currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. FirstEnergy utilizes a 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. FirstEnergy utilizes an analytical tool developed by its actuary to determine the discount rates.
Expected Return on Plan Assets - The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets, the historical performance of risk-based and fixed income securities and other factors. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement.
Pension and OPEB Returns 2024 2023 2022
Actual gains or (losses) on plan assets - $ millions $ 3 $ 751 $ (1,830)
Actual gains or (losses) on plan assets - % 0.7 % 11.2 % (19.1) %
Expected return on plan assets - $ millions $ 565 $ 601 $ 696
Expected return on plan assets - % 8.00% for pension
7.00% for OPEB
8.00% for pension
7.00% for OPEB
7.50 %
Mortality Rates - During 2024, the Society of Actuaries elected not to release a new mortality improvement scale. It was determined that the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due
to the ongoing impact of COVID-19 was most appropriate and such was utilized to determine the obligation as of December 31, 2024, for the FirstEnergy pension and OPEB plans. This adjustment acknowledges COVID-19 cannot be eradicated and assumes reductions in other causes will not offset future COVID-19 deaths enough to produce a normal level of improvements.
Net Periodic Benefit Costs (Credits) - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.
Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB
2024 2023 2022 2024 2023 2022
(In millions)
Service cost(1)
$ 140 $ 139 $ 184 $ 3 $ 2 $ 3
Interest cost 398 428 273 20 21 11
Expected return on plan assets (530) (570) (657) (35) (31) (39)
Amortization of prior service costs (credits) 2 2 2 (1) (8) (11)
Special termination benefits(2)
- 21 - - 8 -
Pension & OPEB mark-to-market 66 108 (98) (44) (30) 26
Net periodic benefit costs (credits) $ 76 $ 128 $ (296) $ (57) $ (38) $ (10)
(1) Includes amounts capitalized.
(2) Related to benefits provided in connection with the PEER.
For the years ended December 31, 2024, 2023 and 2022, approximately $(8) million, $36 million and $15 million, respectively, of the annual pension and OPEB mark-to-market charges (credits) were allocated to companies under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates.
FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement.
In 2024, FirstEnergy recognized a $22 million pension and OPEB mark-to-market adjustment loss, primarily reflecting lower than expected return on assets and demographic changes partially offset by a 67 basis points increase in the discount rate used to measure pension benefit obligations.
The size of the $750 million voluntary contribution made on May 12, 2023, in relation to total pension assets triggered a remeasurement of the pension plan, and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment gain of approximately $59 million in the second quarter of 2023. FirstEnergy elected the practical expedient to remeasure pension plan assets and obligations as of April 30, 2023, which is the month-end closest to the date of the voluntary contribution.
Pension OPEB
Obligations/Funded Status - Qualified and Non-Qualified Plans 2024 2023 2024 2023
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1 $ 8,363 $ 8,828 $ 441 $ 439
Service cost 140 139 3 2
Interest cost 398 428 20 21
Plan participants’ contributions - - 4 4
Special termination benefits - 21 - 8
Medicare retiree drug subsidy - - 1 -
Lift-out transaction - (719) - -
Actuarial loss (gain) (526) 256 (14) 8
Benefits paid (551) (590) (48) (41)
Benefit obligation as of December 31 $ 7,824 $ 8,363 $ 407 $ 441
Change in fair value of plan assets:
Fair value of plan assets as of January 1 $ 6,879 $ 6,693 $ 516 $ 460
Actual return on plan assets (62) 682 65 69
Lift-out transaction - (683) - -
Company contributions 30 777 30 24
Plan participants’ contributions - - 4 4
Benefits paid (551) (590) (48) (41)
Fair value of plan assets as of December 31 $ 6,296 $ 6,879 $ 567 $ 516
Funded Status:
Qualified plan $ (1,165) $ (1,090) $ - $ -
Non-qualified plans (363) (394) - -
Funded Status - Net asset (liability) as of December 31 (1)
$ (1,528) $ (1,484) $ 160 $ 75
Accumulated benefit obligation $ 7,572 $ 7,324 $ - $ -
Amounts Recognized in AOCI:
Prior service cost (credit) $ 2 $ 4 $ 1 $ (1)
(1) The pension net liability is included in “Retirement benefits,” on the Consolidated Balance Sheets. The OPEB net asset is included in “Other” non-current assets on the Consolidated Balance Sheets.
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 11, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2024 and 2023.
December 31, 2024 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 1,173 $ - $ 1,173 19 %
Public equity 1,585 5 - 1,590 25 %
Fixed income - 1,425 - 1,425 23 %
Derivatives (95) 37 - (58) (1) %
Total(1)
$ 1,490 $ 2,640 $ - $ 4,130 66 %
Private - equity and debt funds(2)
1,273 20 %
Insurance-linked securities(2)
39 1 %
Hedge funds(2)
253 4 %
Real estate funds(2)
554 9 %
Total Investments $ 6,249 100 %
(1) Excludes $47 million as of December 31, 2024, of receivables, payables, taxes, cash collateral for derivatives and accrued income associated with financial instruments reflected within the fair value table.
(2) NAV used as a practical expedient to approximate fair value.
December 31, 2023 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 755 $ - $ 755 11 %
Public equity 1,811 4 - 1,815 26 %
Fixed income - 1,784 - 1,784 26 %
Derivatives 2 37 - 39 - %
Total(1)
$ 1,813 $ 2,580 $ - $ 4,393 63 %
Private - equity and debt funds(2)
1,296 19 %
Insurance-linked securities(2)
107 2 %
Hedge funds(2)
410 6 %
Real estate funds(2)
721 10 %
Total Investments $ 6,927 100 %
(1) Excludes $(48) million as of December 31, 2023, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
(2) NAV used as a practical expedient to approximate fair value.
Private - equity and debt funds: Private equity and private debt funds primarily include limited partnerships that invest in equity or directly originated senior loans of high-quality middle market operating companies. Distributions are received periodically through the liquidation of underlying assets in each fund. For most private equity and debt funds, immediate access to capital at the limited partner’s discretion is not available and such funds prevent full redemption and return of capital until fund liquidation. The purpose of each fund is to maximize total return of capital with an emphasis on minimizing default risk. Each fund’s NAV is made available to fund participants quarterly.
Insurance Linked Securities funds: The insurance linked securities funds invest in securities which indirectly participate in portfolios of reinsurance and retrocession contracts which primarily cover catastrophe property risks. Redemptions can be achieved with 90-day notices with gating factors that may apply. The purpose of these investments is to generate attractive risk-adjusted returns that are demonstrably uncorrelated with traditional asset classes. Each fund’s NAV is made available to fund participants monthly.
Hedge funds: The hedge funds invest in a combination of long and short equity, multi-strategy, global macro and structured credit strategies. Redemptions can be achieved with 90-day notices with gating factors that may apply. The purpose of these investments is to deliver diversified risk-adjusted returns to traditional asset classes. Each fund’s NAV is made available to fund participants monthly.
Real estate funds: The real estate funds primarily invest in U.S commercial real estate markets that include office, residential, retail, industrial, life science/lab space, storage and student housing. The investment values of the real estate properties are determined on a quarterly basis by independent market appraisers hired by the board of directors of each fund. Distributions from each fund will be received as the underlying investments of the fund are liquidated. Each investor’s ability to withdraw capital from certain funds may be limited depending on whether a queue has been established. The purpose of each fund is to invest in real estate and real estate related assets that generate a total return from current income and capital appreciation which exceeds the applicable fund’s index. Each fund’s NAV is made available to fund participants quarterly.
As of December 31, 2024, and 2023, the OPEB trust investments measured at fair value were as follows:
December 31, 2024 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 112 $ - $ 112 20 %
Public equity 314 - - 314 55 %
Fixed income - 146 - 146 25 %
Total(1)
$ 314 $ 258 $ - $ 572 100 %
(1) Excludes $(5) million as of December 31, 2023, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
December 31, 2023 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 100 $ - $ 100 19 %
Public equity 258 - - 258 50 %
Fixed income: - 158 - 158 31 %
Total(1)
$ 258 $ 258 $ - $ 516 100 %
FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2024 were as follows:
Target Asset Allocations
Pension OPEB
Equities 30 % 50 %
Fixed income 28.5 % 50 %
Alternative investments 5 % - %
Real estate 10 % - %
Private - equity and debt funds 20 % - %
Cash and derivatives 6.5 % - %
100 % 100 %
FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies.
Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contribution.
OPEB
Pension Benefit Payments Benefit Payments (1)
Subsidy Receipts
(In millions)
2025 $ 1,150 $ 43 $ -
2026 514 42 (1)
2027 519 41 -
2028 524 39 (1)
2029 528 37 -
Years 2030-2034 2,652 163 (3)
(1) Net of participant contributions.
6. STOCK-BASED COMPENSATION PLANS
FirstEnergy grants stock-based awards through the ICP 2020, primarily in the form of restricted stock and performance-based restricted stock units. No shares are available for future grants or issuance under ICP 2015.
The ICP 2020 and ICP 2015 include shareholder authorization to each issue 10 million shares of common stock or their equivalent. Shares not issued due to forfeitures or cancellations originally granted through the ICP 2015 may be added back to the ICP 2020. As of December 31, 2024, approximately 8.5 million shares were available for future grants under the ICP 2020 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. Shares granted under the ICP 2020 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from less
than a year, primarily due to the issuance of prorated awards to newly hired executives, to four years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) savings plan and DCPD.
Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur.
FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2024, 2023 and 2022, were $17 million, $6 million and $8 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited.
Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2024, 2023 and 2022, are included in the following tables:
For the Years Ended December 31,
Stock-based Compensation Plan 2024 2023 2022
(In millions)
Restricted stock units $ 32 $ 39 $ 55
Restricted stock 7 5 3
401(k) savings plan 41 38 36
EDCP & DCPD 6 1 7
Total $ 86 $ 83 $ 101
Stock-based compensation costs, net of amounts capitalized $ 43 $ 44 $ 54
Income tax benefits associated with stock-based compensation plan expense were $5 million, $6 million and $8 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Restricted Stock Units
Two-thirds of each performance-based restricted stock unit award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair market value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Restricted stock units include a performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method. Beginning with awards granted in 2022, restricted stock units include a relative total shareholder return as a performance metric, weighted at 35%, utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is also calculated using the Monte Carlo simulation method. In addition, outstanding awards are subject to an absolute total shareholder return, if FirstEnergy's total shareholder return is negative for the three-year cumulative performance period, restricted stock unit awards will be capped at a payout of 100%.
Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2024, was $14 million. During 2024, approximately $17 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2024.
The vesting period for the performance-based restricted stock unit awards granted in 2024, 2023 and 2022, were each approximately three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award.
Restricted stock unit activity for the year ended December 31, 2024, was as follows:
Restricted Stock Unit Activity Shares
(in millions)
Weighted-Average Grant Date Fair Value (per share)
Nonvested as of January 1, 2024
2.5 $ 38.82
Granted in 2024
2.0 36.79
Forfeited in 2024
(0.2) 38.08
Vested in 2024(1)
(1.5) 36.61
Nonvested as of December 31, 2024
2.8 $ 37.32
(1) Excludes dividend equivalents of approximately 175 thousand shares earned during vesting period.
The weighted-average fair value per share of awards granted in 2024, 2023 and 2022 was $36.79, $38.36 and $41.49 per share, respectively. During the years ended 2024, 2023, and 2022, the fair value of restricted stock units vested was $55 million, $24 million, and $26 million, respectively. As of December 31, 2024, there was approximately $30 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years.
Restricted Stock
Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended 2024, was as follows:
Restricted Stock Activity Shares
(in millions)
Weighted-Average Grant Date Fair Value (per share)
Nonvested as of January 1, 2024
0.46 $ 39.57
Granted in 2024
0.03 40.26
Forfeited in 2024
(0.01) 42.24
Vested in 2024
(0.21) 41.02
Nonvested as of December 31,2024
0.27 $ 38.29
The weighted average vesting period for restricted stock granted in 2024 was 2.6 years. As of December 31, 2024, there was $5 million of total unrecognized compensation cost related to non-vested restricted stock, which is expected to be recognized over a period of approximately 3 years.
401(k) Savings Plan
In each of 2024 and 2023, approximately 1 million shares of FE common stock, respectively, were issued and contributed to employee participants' accounts.
EDCP
Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts, where they are tracked as units. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividend equivalents are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. Awards deferred into a retirement stock account will pay out in cash upon separation, including retirement, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash as a lump sum or over a defined period of time period as elected by the participant. The liability recognized for EDCP of approximately $166 million and $175 million as of December 31, 2024 and 2023, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets.
DCPD
Under the DCPD, members of the FE Board can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $4 million as of December 31, 2024 and 2023, is included in “Retirement benefits,” on the Consolidated Balance Sheets.
7. TAXES
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FE and its subsidiaries, other than FET and its subsidiaries, are parties to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. For periods subsequent to the closing of the FET Equity Interest Sale, FET and its subsidiaries are no longer members of the FirstEnergy consolidated group for federal income tax purposes and, instead, will file their own consolidated federal income tax return and have their own income tax allocation agreement.
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 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. 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 expected taxable income in 2024. Due to certain limitations on NOL utilization enacted in the Tax Act, approximately $1.6 billion NOL will carry 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. Previously, in the fourth quarter of 2023, FirstEnergy recognized a charge to income tax expense of approximately $58 million as a true-up of the deferred tax liability associated with the deferred tax gain.
FirstEnergy is continuing to evaluate the potential requirement to transition certain of its Electric Companies and Transmission Companies to standalone treatment for computing NOL carryforward deferred tax assets for rate making purposes and expects that if and where transitioning is required, those impacted Electric Companies and Transmission Companies will make the appropriate regulatory filing(s) in their applicable jurisdiction to include the NOL carryforward deferred tax asset in rate base and revenue requirement, which could have a material, favorable impact on future net income.
The following table provides the composite of income taxes on income from continuing operations for the years ended 2024, 2023 and 2022:
INCOME TAXES ON INCOME FROM CONTINUING OPERATIONS For the Years Ended December 31,
2024 2023 2022
(In millions)
Currently payable -
Federal $ 32 $ 14 $ -
State 29 1 11
61 15 11
Deferred, net -
Federal(1)
190 279 946
State 130 (24) 47
320 255 993
Investment tax credit amortization (4) (3) (4)
Total income taxes on income from continuing operations $ 377 $ 267 $ 1,000
(1) Excludes $21 million of federal tax expense associated with discontinued operations for the year ended December 31, 2023.
FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period but are not consistent from period to period. The following table provides a reconciliation of federal income tax expense at the federal statutory rate to the total income taxes on income from continuing operations for the years ended December 31, 2024, 2023 and 2022:
For the Years Ended December 31,
2024 2023 2022
(In millions)
Income from continuing operations, before income taxes $ 1,504 $ 1,464 $ 1,439
Federal income tax expense at the 21% statutory rate $ 316 $ 307 $ 302
Increases (reductions) in taxes resulting from-
State and municipal income taxes, net of federal tax benefit 140 80 56
AFUDC equity and other flow-through (30) (30) (26)
Amortization of investment tax credits (4) (3) (4)
Deductions associated with certain equity method investments (19) - -
Taxes related to the combined sale of 49.9% of the equity interests of FET 6 58 752
Federal tax credits claimed (2) (3) (3)
Tax on distributions from FET 16 - -
Excess deferred tax amortization due to the Tax Act (52) (46) (51)
Nondeductible SEC and OAG settlements 27 - -
Remeasurement of excess deferred income taxes (43) - -
Uncertain tax positions - 41 2
Valuation allowances 16 (146) (47)
Other, net 6 9 19
Total income taxes on income from continuing operations $ 377 $ 267 $ 1,000
Effective income tax rate (continuing operations) 25.1 % 18.2 % 69.5 %
Net accumulated deferred income tax liabilities (assets) as of December 31, 2024 and 2023, are as follows:
As of December 31,
2024 2023
(In millions)
Property basis differences $ 6,079 $ 5,787
Pension and OPEB (322) (331)
Regulatory asset/liability 744 647
Deferred compensation (127) (153)
Deferred gain on 19.9% FET equity interest sale
- 810
Loss carryforwards and tax credits (762) (2,192)
Valuation allowances 240 226
Other (239) (264)
Net accumulated deferred income tax liability $ 5,613 $ 4,530
FirstEnergy has recorded as deferred income tax assets the effect of federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2024, FirstEnergy's loss carryforwards primarily consisted of $1.6 billion ($343 million, net of tax) of federal NOL carryforwards, all of which have no expiration.
The table below summarizes pre-tax NOL carryforwards and their respective anticipated expirations for state and local income tax purposes of approximately $12.9 billion ($403 million, million net of tax) for FirstEnergy, of which approximately $4.7 billion ($185 million, million net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions.
Expiration Period State Local
(In millions)
2025-2029 $ 1,569 $ 5,706
2030-2034 1,279 -
2035-2039 881 -
2040-2044 978 -
Indefinite 2,450 -
$ 7,157 $ 5,706
The following table summarizes the changes in valuation allowances on federal, state, and local deferred tax assets related to business interest expense carryforwards and employee compensation deduction limitations under section 162(m), in addition to state and local NOLs discussed above for the years ended December 31, 2024, 2023 and 2022:
(In millions) 2024 2023 2022
Beginning of year balance $ 226 $ 440 $ 484
Charged to income 14 (214) (44)
Charged to other accounts - - -
Write-offs - - -
End of year balance $ 240 $ 226 $ 440
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. If ultimately recognized in future years, all of the unrecognized income tax benefits would impact the effective tax rate.
The following table summarizes the changes (gross) in uncertain tax positions for the years ended December 31, 2024, 2023 and 2022:
(In millions)
Balance, January 1, 2022 $ 47
Prior year increases 2
Decrease for lapse in statute (7)
Balance, December 31, 2022 $ 42
Prior year increases 88
Effectively settled with taxing authorities (24)
Decrease for lapse in statute (1)
Balance, December 31, 2023 $ 105
Prior years increases -
Effectively settled with taxing authorities -
Decrease for lapse in statute -
Balance, December 31, 2024 $ 105
As of December 31, 2024, none of the unrecognized tax benefits are expected to be resolved during 2025.
FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes interest expense or income and penalties in the provision for income taxes. Due to uncertain tax positions that were effectively settled with tax authorities during 2023, approximately $9 million in net interest was reversed. There was no material interest expense or income, or penalties, related to uncertain tax positions in 2024, nor does FirstEnergy have a cumulative net interest payable as of December 31, 2024.
IRS review of FirstEnergy's federal income tax return is complete through the 2020 tax year with no pending adjustments. FirstEnergy's tax returns for some state jurisdictions are open from tax years 2015-2023.
General Taxes
General tax expense for the years ended December 31, 2024, 2023 and 2022, recognized in continuing operations is summarized as follows:
For the Years Ended December 31,
2024 2023 2022
(In millions)
kWh excise $ 186 $ 185 $ 191
State gross receipts 247 235 219
Real and personal property 642 615 596
Social security and unemployment 113 113 105
Other 24 16 18
Total general taxes $ 1,212 $ 1,164 $ 1,129
8. LEASES
FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.
FirstEnergy accounts for leases under, "Leases (Topic 842)". Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. FirstEnergy has elected a policy to not separate lease components from non-lease components for all asset classes.
For vehicles leased under certain master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, FirstEnergy is committed to pay the difference in the actual fair value and the residual value guarantee. FirstEnergy does not believe it is probable that it will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly.
In December 2023, FirstEnergy exercised a purchase option within their lease to purchase the General Office building in Akron, Ohio, with the intention to sell it in the future.
Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense recorded for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:
For the Year Ended December 31, 2024
(In millions) Vehicles Buildings Other Total
Operating lease costs(1)
$ 82 $ 3 $ 6 $ 91
Finance lease costs:
Amortization of right-of-use assets 1 1 2 4
Interest on lease liabilities - 2 - 2
Total finance lease cost 1 3 2 6
Total lease cost $ 83 $ 6 $ 8 $ 97
(1) Includes $35 million of short-term lease costs.
For the Year Ended December 31, 2023
(In millions) Vehicles Buildings Other Total
Operating lease costs(1)
$ 60 $ 5 $ 14 $ 79
Finance lease costs:
Amortization of right-of-use assets 4 2 2 8
Interest on lease liabilities - 5 - 5
Total finance lease cost 4 7 2 13
Total lease cost $ 64 $ 12 $ 16 $ 92
(1) Includes $27 million of short-term lease costs.
For the Year Ended December 31, 2022
(In millions) Vehicles Buildings Other Total
Operating lease costs(1)
$ 50 $ 8 $ 15 $ 73
Finance lease costs:
Amortization of right-of-use assets 10 1 2 13
Interest on lease liabilities - 3 - 3
Total finance lease cost 10 4 2 16
Total lease cost $ 60 $ 12 $ 17 $ 89
(1) Includes $19 million of short-term lease costs.
Supplemental cash flow information related to leases was as follows:
For the Years Ended December 31,
(In millions) 2024 2023 2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 60 $ 54 $ 56
Operating cash flows from finance leases 2 3 3
Finance cash flows from finance leases 2 8 12
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 69 $ 13 $ 26
Finance leases - - -
Lease terms and discount rates were as follows:
As of December 31,
2024 2023 2022
Weighted-average remaining lease terms (years)
Operating leases 5.62 5.93 7.30
Finance leases 12.38 12.26 11.33
Weighted-average discount rate(1)
Operating leases 5.00 % 4.51 % 4.22 %
Finance leases 15.39 % 14.73 % 14.77 %
(1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.
Supplemental balance sheet information related to leases was as follows:
As of December 31,
(In millions) Financial Statement Line Item 2024 2023
Assets
Operating lease(1)
Deferred charges and other assets $ 228 $ 205
Finance lease(2)
Property, plant and equipment 32 35
Total leased assets $ 260 $ 240
Liabilities
Current:
Operating Other current liabilities $ 51 $ 47
Finance Currently payable long-term debt 3 3
Noncurrent:
Operating Other noncurrent liabilities 192 179
Finance Long-term debt and other long-term obligations 9 11
Total leased liabilities $ 255 $ 240
(1) Operating lease assets are recorded net of accumulated amortization of $174 million and $139 million as of December 31, 2024 and 2023, respectively.
(2) Finance lease assets are recorded net of accumulated amortization of $14 million and $33 million as of December 31, 2024 and 2023, respectively.
Maturities of lease liabilities as of December 31, 2024, were as follows:
(In millions) Operating Leases Finance Leases Total
2025 $ 61 $ 4 $ 65
2026 56 4 60
2027 48 3 51
2028 43 4 47
2029 28 - 28
Thereafter 46 - 46
Total lease payments(1)
282 15 297
Less imputed interest 39 3 42
Total net present value $ 243 $ 12 $ 255
(1) Operating lease payments for certain leases are offset by sublease receipts of $7 million over 8 years.
As of December 31, 2024, lease agreements for vehicles and fiber lines that have not yet commenced are $40 million, which are expected to commence from 2025-2029 with lease terms of 5 to 30 years. Additionally, a building lease agreement is expected to commence in 2025 with a lease term of 22 years with annual rents of approximately $2 million.
9. VARIABLE INTEREST ENTITIES
FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance.
Consolidated VIEs
Total assets on FirstEnergy's Consolidated Balance Sheets include approximately $12 billion and $11 billion of consolidated VIE assets, as of December 31, 2024 and 2023, respectively, that can only be used to settle the liabilities of the applicable VIE. Total liabilities include approximately $9.1 billion and $7.8 billion as of December 31, 2024 and 2023, respectively, of consolidated VIE liabilities for which the VIE's creditors do not have recourse to FirstEnergy.
VIEs in which FirstEnergy is the primary beneficiary consist of the following 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 utility. As of December 31, 2024 and 2023, $175 million and $191 million of the phase-in recovery bonds were outstanding, respectively.
•MP and PE Environmental Funding Companies - The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2024 and 2023, $188 million and $218 million of environmental control bonds were outstanding, respectively.
FirstEnergy's Consolidated Balance Sheets includes restricted cash of $40 million as of December 31, 2024 and 2023 which is related to cash collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies.
FET
FET is a holding company that owns equity interests in ATSI, MAIT, TrAIL and PATH. As further discussed above, on February 2, 2023, FE entered into an agreement with Brookfield to sell an incremental 30% equity interest in FET, which closed on March 25, 2024. As of December 31, 2024 FE’s equity ownership in FET is 50.1% and Brookfield’s is 49.9%. FirstEnergy has concluded that FET is a VIE and that FE is the primary beneficiary because FE has exposure to the economics of FET and the power to direct significant activities of FET through the FESC services agreement, which represents a separate variable interest.
Although Brookfield was granted incremental consent rights upon the closing of the FET Equity Interest Sale, Brookfield will not have unilateral control over any activities that most significantly impact FET’s economic performance. However, FE will continue to retain power over the activities that most significantly impact FET’s economic performance through its incremental decision making rights under the existing FESC services agreement, through which executive management and workforce services are provided to FET. As a result, FE is the primary beneficiary of FET, which will continue to be consolidated in FirstEnergy’s financial statements.
The following shows the carrying amounts and classification of the FET assets and liabilities included in the consolidated financial statements as of December 31, 2024 and 2023. Amounts exclude intercompany balances which were eliminated in consolidation. The assets of FET can only be used to settle its obligations, and creditors of FET do not have recourse to the general credit of FirstEnergy.
Assets December 31,
2024 December 31,
Cash and cash equivalents $ 8 $ 76
Receivables 94 88
Materials and supplies, at average cost 1 1
Prepaid taxes and other 21 23
Total current assets 124 188
Property, plant and equipment, net 11,217 10,227
Goodwill 224 224
Investments 19 19
Regulatory assets 18 16
Other 334 310
Total noncurrent assets 11,812 10,796
TOTAL ASSETS $ 11,936 $ 10,984
Liabilities December 31,
2024 December 31,
Currently payable long-term debt $ 625 $ -
Short-term borrowings 300 -
Accounts payable - 2
Accrued interest 68 63
Accrued taxes 306 262
Other 15 14
Total current liabilities 1,314 341
Long-term debt and other long-term obligations 5,239 5,275
Accumulated deferred income taxes 1,412 1,218
Regulatory liabilities 442 307
Other 299 285
Total noncurrent liabilities 7,392 7,085
TOTAL LIABILITIES $ 8,706 $ 7,426
Unconsolidated VIEs
FirstEnergy is not the primary beneficiary of its equity method investments in Global Holding and PATH WV, as further discussed above, or its PPAs.
FirstEnergy evaluated its PPAs and determined that certain Non-Utility Generation entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. As of December 31, 2024, FirstEnergy maintains four long-term PPAs with NUG entities that were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE.
Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Distribution and Integrated segments to be recovered from customers.
10. ASSET RETIREMENT OBLIGATIONS
FirstEnergy recognizes an ARO for its legal obligation to perform asset retirement activities associated with its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation such that the ARO is accreted monthly to reflect the time value of money.
A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the remediation AROs, taking into account the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. For instances where asset retirement costs relate to assets that have no future cash flows, the costs are recorded as an operating expense. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition.
FirstEnergy has recognized applicable legal obligations for AROs and their associated costs, including reclamation of sludge disposal ponds, closure of CCR sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.
The following table summarizes the changes to the ARO balances during 2024 and 2023:
ARO Reconciliation (In millions)
Balance, January 1, 2023 $ 185
Changes in timing and amount of estimated cash flows 10
Liabilities settled (2)
Accretion 16
Balance, December 31, 2023 $ 209
Changes in timing and amount of estimated cash flows 131
Liabilities incurred 95
Liabilities settled (4)
Accretion 24
Balance, December 31, 2024 $ 455
On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of December 31, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. During the second quarter of 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 and corresponding increase to “Other operating expense” of $87 million at Corporate/Other for segment reporting. On February 3, 2025, AE Supply executed an environmental liability transfer agreement with a subsidiary of IDA Power, LLC, whereby AE Supply will transfer the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations. The agreement requires
AE Supply to establish a $160 million escrow account that AE Supply will fund over five years. The escrow funding obligation will be secured by a surety bond, which will be guaranteed by FE. The transaction is expected to close before the end of the first quarter of 2025 and the derecognition of the ARO is not expected to have a material impact to FirstEnergy’s financial statements, however, no assurances of the closing of the transfer will be satisfied, including transfer of all required environmental permits.
As further discussed below, on May 8, 2024, the EPA finalized changes to the CCR rule addressing certain legacy CCR disposal sites which were not included in previous CCR rules. 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. As a result, FirstEnergy recorded a $139 million increase to its ARO in 2024, of which $113 million is included in “Other operating expenses” on the Consolidated Statements of Income and was not capitalized as an asset retirement cost since the associated plants are closed. Of the $113 million expensed in 2024, $16 million is included with Integrated, $46 million is included within Distribution and $51 million at Corporate/Other for segment reporting.
The ARO increase related to certain legacy CCR disposal sites represents the discounted cash flows for estimated closure costs based upon the potential closure requirements as evaluated on a site-by-site basis. Actual costs to be incurred will be dependent upon factors that vary from site to site. The most significant factors include the method and time frame of closure at the individual sites, which will be determined based on the groundwater monitoring and, if applicable, EPA approval of closure plans. In determining the estimated closure costs for each site, FirstEnergy has assumed the anticipated applicable closure method, however, alternative closure methods may be required, resulting in greater or lesser cost. As a result, the ARO liability may be adjusted as additional information is gained through the evaluation and closure process, including further inspection of the sites, results of groundwater monitoring and changes in interpretation of the CCR regulations which may change management assumptions, and could result in a material change to the ARO liability balance and FirstEnergy’s results of operations.
11. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:
Level 1 - Quoted prices for identical instruments in active market
Level 2 - Quoted prices for similar instruments in active market
- Quoted prices for identical or similar instruments in markets that are not active
- Model-derived valuations for which all significant inputs are observable market data
Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
Level 3 - Valuation inputs are unobservable and significant to the fair value measurement
FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value.
FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.
FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2024, from those used as of December 31, 2023. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.
For investments reported at NAV where there is no readily determinable fair value, a practical expedient is available that allows the NAV to approximate fair value. Investments that use NAV as a practical expedient are excluded from the requirement to be categorized within the fair value hierarchy tables. Instead, these investments are reported outside of the fair value hierarchy
tables to assist in the reconciliation of investment balances reported in the tables to the balance sheet. FirstEnergy has elected the NAV practical expedient for investments in private equity funds, insurance-linked securities, hedge funds (absolute return) and real estate funds held within the pension plan. See Note 5, "Pension and Other Postemployment Benefits" for the pension financial assets accounted for at fair value by level within the fair value hierarchy.
The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:
December 31, 2024 December 31, 2023
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Derivative assets FTRs(1)
$ - $ - $ 7 $ 7 $ - $ - $ 4 $ 4
Equity securities 2 - - 2 2 - - 2
U.S. state debt securities - 276 - 276 - 275 - 275
Cash, cash equivalents and restricted cash(2)
154 - - 154 179 - - 179
Other(3)
- 45 - 45 - 40 - 40
Total assets $ 156 $ 321 $ 7 $ 484 $ 181 $ 315 $ 4 $ 500
Liabilities
Derivative liabilities FTRs(1)
$ - $ - $ - $ - $ - $ - $ (1) $ (1)
Total liabilities $ - $ - $ - $ - $ - $ - $ (1) $ (1)
Net assets (liabilities) $ 156 $ 321 $ 7 $ 484 $ 181 $ 315 $ 3 $ 499
(1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.
(2) Restricted cash of $43 million and $42 million as of December 31, 2024 and 2023, respectively, primarily relates to cash collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies. See Note 12, Capitalization for additional information.
(3) Primarily consists of short-term investments.
INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.
Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the JCP&L spent nuclear fuel disposal trusts are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.
Spent Nuclear Fuel Disposal Trusts
JCP&L holds debt securities within the spent nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value. The trust is intended for funding spent nuclear fuel disposal fees to the United States Department of Energy associated with the previously owned Oyster Creek and Three Mile Island Unit 1 nuclear power plants.
The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in nuclear fuel disposal trusts as of December 31, 2024 and 2023:
December 31, 2024(1)
December 31, 2023(2)
Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value
(In millions)
Debt securities $ 299 $ - $ (23) $ 276 $ 301 $ 1 $ (27) $ 275
(1) Excludes short-term cash investments of $6 million.
(2) Excludes short-term cash investments of $6 million.
Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2024, 2023 and 2022, were as follows:
For the Years Ended December 31,
2024 2023 2022
(In millions)
Sale Proceeds $ 121 $ 38 $ 48
Realized Gains - - 8
Realized Losses (15) (3) (13)
Interest and Dividend Income 13 12 11
Other Investments
Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies and equity method investments. Earnings and losses associated with corporate-owned life insurance policies and equity method investments are reflected in the “Miscellaneous Income, net” line of FirstEnergy’s Consolidated Statements of Income. Other investments were $370 million and $382 million as of December 31, 2024 and 2023, respectively, and are excluded from the amounts reported above. See Note 1, "Organization and Basis of Presentation," for additional information on FirstEnergy's equity method investments.
For the years ended December 31, 2024, 2023 and 2022, pre-tax income (expense) related to corporate-owned life insurance policies were $16 million, $18 million and $(20) million, respectively. Corporate-owned life insurance policies are valued using the cash surrender value and any changes in value during the period are recognized as income or expense.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts as of December 31, 2024 and 2023:
As of December 31,
2024 2023
(In millions)
Carrying Value $ 23,594 $ 24,254
Fair Value 22,128 $ 23,003
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2024 and 2023.
See Note 12, "Capitalization," for further information on long-term debt issued and redeemed during the twelve months ended December 31, 2024.
12. CAPITALIZATION
COMMON STOCK
Dividends
Dividends declared and paid per share of common stock during 2024 and 2023 were as follows:
Dividends Declared Dividends Paid
2024 2023 2024 2023
Q1 $ 0.425 $ 0.390 $ 0.410 $ 0.390
Q2 - 0.390 0.425 0.390
Q3 0.850 0.410 0.425 0.390
Q4 0.425 0.410 0.425 0.410
Total $ 1.700 $ 1.600 $ 1.685 $ 1.580
The amount and timing of all dividend declarations are subject to the discretion of the FE Board and its consideration of business conditions, results of operations, financial condition, and other factors. In addition to declaring dividends from retained earnings, FE can declare dividends from paid-in capital accounts.
When FE makes distributions to shareholders, it is required to subsequently determine and report the tax characterization of those distributions for purposes of shareholders’ income taxes. Whether a distribution is characterized as a dividend or a return of capital (and possible capital gain) depends upon an internal tax calculation to determine earnings and profits for income tax purposes. Earnings and profits should not be confused with earnings or net income under GAAP. Further, after FE reports the expected tax characterization of distributions it has paid, the actual characterization could vary from its expectation with the result that holders of FE's common stock could incur different income tax liabilities than expected.
In general, distributions are characterized as dividends to the extent the amount of such distributions do not exceed FE's calculation of current or accumulated earnings and profits. Distributions in excess of current and accumulated earnings and profits may be treated as a non-taxable return of capital. Generally, a non-taxable return of capital will reduce an investor’s basis in FirstEnergy's stock for federal tax purposes, which will impact the calculation of gain or loss when the stock is sold.
Based on the closing of the FET Equity Interest Sale on March 25, 2024, FE realized an approximate $7 billion tax gain in 2024. FE expects that this tax gain created sufficient earnings and profits to cause distributions made during 2024 and the next several years, to be characterized as dividends for federal income tax purposes. Upon such characterization, shareholders are urged to consult their own tax advisors regarding the income tax treatment of FE's distributions to them.
In addition to paying dividends from retained earnings, the Ohio Companies and JCP&L have authorization from FERC to pay cash dividends to FE from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent, MP, from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The governance documents, indentures, regulatory limitations, and FET P&SA II, and various other agreements, including those relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2024.
Common Stock Issuance
FE issued approximately 3 million shares of common stock in 2024, 2 million shares of common stock in 2023 and 2 million shares of common stock in 2022 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans.
PREFERRED AND PREFERENCE STOCK
FirstEnergy and certain of its subsidiaries are authorized to issue preferred stock and preference stock as of December 31, 2024, as follows:
Preferred Stock Preference Stock
Shares Authorized Par Value Shares Authorized Par Value
FE 5,000,000 $ 100
OE 6,000,000 $ 100 8,000,000 no par
OE 8,000,000 $ 25
CEI 4,000,000 no par 3,000,000 no par
TE 3,000,000 $ 100 5,000,000 $ 25
TE 12,000,000 $ 25
JCP&L 15,600,000 no par
MP 940,000 $ 100
PE 10,000,000 $ 0.01
As of December 31, 2024 and 2023, there were no preferred stock or preference stock outstanding.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2024 and 2023:
As of December 31, 2024 As of December 31,
Maturity Date Interest Rate 2024 2023
(In millions)
FMBs and secured notes - fixed rate 2026-2059 2.650% - 8.250%
$ 4,963 $ 5,709
Unsecured notes - fixed rate 2025-2050 1.600% - 6.875%
18,631 18,545
Finance lease obligations 12 14
Unamortized debt discounts (14) (9)
Unamortized debt issuance costs (122) (127)
Unamortized fair value adjustments 3 3
Currently payable long-term debt (977) (1,250)
Total long-term debt and other long-term obligations $ 22,496 $ 22,885
See Note 8, "Leases," for additional information related to finance leases.
FirstEnergy had the following redemptions and issuances during the twelve months ended December 31, 2024:
Company Type Redemption/Issuance Date Interest Rate Maturity Amount
(In millions) Description
Redemptions(1)
FE Unsecured Notes April, 2024 7.375% 2031 $463 FE redeemed all of its remaining $463 million of 2031 Notes including a premium of approximately $80 million ($63 million after-tax). In addition, FE recognized approximately $4 million ($3 million after-tax) of deferred cash flow hedge losses and $1 million in other unamortized debt costs and fees associated with the FE debt redemptions.
JCP&L Unsecured Notes April, 2024 4.70% 2024 $500 JCP&L redeemed unsecured notes that became due.
MP FMBs April, 2024 4.10% 2024 $400 MP redeemed FMBs that became due.
CEI FMBs August, 2024 5.50% 2024 $300 CEI redeemed FMBs that became due.
FE PA Unsecured Notes December, 2024 4.00% 2025 $250 On December 30, 2024, FE PA caused to be redeemed $250 million of 4.00% senior notes due 2025.
FE PA Unsecured Notes December, 2024 4.15% 2025 $200 On December 30, 2024, FE PA caused to be redeemed $200 million of 4.15% senior notes due 2025.
FET Unsecured Notes December, 2024 4.35% 2025 $600 On December 30, 2024, FET caused to be redeemed $600 million of 4.35% senior notes due 2025.
Issuances
ATSI Unsecured Notes March, 2024 5.63% 2034 $150 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
MAIT Unsecured Notes May, 2024 5.94% 2034 $250 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
FET Unsecured Notes with registration rights September, 2024 4.55% 2030 $400 Proceeds were used to repay short-term borrowings, to redeem FET's $600 million 4.35% notes due 2025, to finance capital expenditures and for other general corporate purposes.
FET Unsecured Notes with registration rights September, 2024 5.00% 2035 $400 Proceeds were used to repay short-term borrowings, to redeem FET's $600 million 4.35% notes due 2025, to finance capital expenditures and for other general corporate purposes.
KATCo Unsecured Notes November, 2024 5.17% 2035 $200 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
JCP&L Unsecured Notes with registration rights December, 2024 5.10% 2035 $700 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
(1) Excludes principal payments on securitized bonds.
As noted above, on September 5, 2024, FET issued $400 million of unsecured senior notes due in 2030 and $400 million of unsecured senior notes due in 2035 in a private offering that included a registration rights agreement in which FET agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act. On October 8, 2024, FET filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on December 20, 2024. On January 24, 2025, FET completed an exchange offer of these senior notes for like principal amounts registered under the Securities Act.
As noted above, 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. JCP&L also agreed to file a shelf registration statement with the SEC to cover resales of the senior notes under certain circumstances. In the event that JCP&L's exchange offer is not completed or the shelf registration statement, if required, is not effective by the 366th day after December 5, 2024, or the effective shelf registration stops being effective for 60 days during any 12-month period, then additional interest will accrue on the coupon. Interest will accrue at a rate of 25 basis points for the first 90 days and an additional 25 basis points in the subsequent 90-day period, but not to exceed 50 basis points per year. However, if the additional interest is triggered, the interest rate will reset to the original notes rate once the registration statement is effective, or the shelf registration, if required, becomes effective. JCP&L plans to file a registration statement for the exchange offer before the end of the first quarter of 2025.
The following table presents scheduled debt repayments or debt that has been noticed for redemption for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2024.
(In millions) 2025 2026 2027 2028 2029
Scheduled debt repayments $973 $2,876 $2,003 $2,453 $1,064
Convertible Notes
As discussed above, on May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, with a fixed interest rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. However, FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date. The 2026 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $1.48 billion, net of issuance costs.
Prior to the close of business on the business day immediately preceding February 1, 2026, the 2026 Convertible Notes will be convertible at the option of the holders only under the following conditions:
•During any calendar quarter, if the last reported sale price of FE’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;
•During the five consecutive business day period immediately after any 10 consecutive trading day period in which the trading price per $1,000 principal amount of the 2026 Convertible Notes for each trading day of such 10 trading day period was less than 98% of the product of the last reported sale price of FE’s common stock and the conversion rate on each such trading day; or
•Upon the occurrence of certain corporate events specified in the indenture governing the 2026 Convertible Notes.
On and after February 1, 2026, until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2026 Convertible Notes may convert all or any portion of their 2026 Convertible Notes at their option at any time at the conversion rate then in effect, irrespective of these conditions. FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash up to the aggregate principal amount of the 2026 Convertible Notes being converted and by paying cash or delivering shares of FE’s common stock (or a combination of each), at its election, of its conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted.
The conversion rate for the 2026 Convertible Notes will initially be 21.3620 shares of FE’s common stock per $1,000 principal amount of the 2026 Convertible Notes (equivalent to an initial conversion price of approximately $46.81 per share of FE’s common stock). The initial conversion price of the 2026 Convertible Notes represents a premium of approximately 20% over the last reported sale price of FE’s common stock on the New York Stock Exchange on May 1, 2023. The conversion rate and the corresponding conversion price will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.
If FE undergoes a fundamental change (as defined in the relevant indenture), subject to certain conditions, holders of the 2026 Convertible Notes may require FE to repurchase for cash all or any portion of their 2026 Convertible Notes at a repurchase price equal to 100% of the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date (as defined in the relevant indenture). In addition, if certain fundamental changes occur, FE may be required, in certain circumstances, to increase the conversion rate for any 2026 Convertible Notes converted in connection with such fundamental changes by a specified number of shares of its common stock.
Securitized Bonds
Environmental Control Bonds
The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2024 and 2023, $188 million and $218 million of environmental control bonds were outstanding, respectively.
Phase-In Recovery Bonds
In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2024 and 2023, $175 million and $191 million of the phase-in recovery bonds were outstanding, respectively.
FMBs
The Ohio Companies, FE PA, MP and PE each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. The outstanding debt under the FMBs of specific FE PA predecessors (WP and Penn) were assumed by FE PA.
Debt Covenant Default Provisions
FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2024, FirstEnergy remains in compliance with all debt covenant provisions.
Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it, or any of its significant subsidiaries, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Such defaults by any of the Electric Companies or Transmission Companies would cross-default certain FE financing arrangements containing these provisions, and a certain FET Financing arrangement, with respect to the Transmission Companies only. Such defaults by AE Supply would not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or its subsidiaries.
13. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
FirstEnergy had $550 million and $775 million of outstanding short-term borrowings as of December 31, 2024 and 2023, respectively.
On October 24, 2024, FE and certain of its subsidiaries entered into the following amendments to each of the 2021 Credit Facilities to, among other things: (i) extend the maturity date of the 2021 Credit Facilities for an additional one-year period, from October 18, 2027 to October 18, 2028, and (ii) increase the borrowing limit of the JCP&L credit facility from $500 million to $750 million. Also on October 24, 2024, each of FET and KATCo entered into amendments of the 2023 Credit Facilities, to, among other things, extend the maturity date of the 2023 Credit Facilities for an additional one-year period, from October 20, 2028 to October 20, 2029 and from October 20, 2027 to October 20, 2028, for the FET credit facility and KATCo credit facility, respectively.
The 2021 Credit Facilities and 2023 Credit Facilities, as amended on October 24, 2024, are as follows:
•FE, $1.0 billion revolving credit facility;
•FET, $1.0 billion revolving credit facility;
•Ohio Companies, $800 million revolving credit facility;
•FE PA, $950 million revolving credit facility;
•JCP&L, $750 million revolving credit facility;
•MP and PE, $400 million revolving credit facility;
•ATSI, MAIT and TrAIL, $850 million revolving credit facility; and
•KATCo, $150 million revolving credit facility.
As of December 31, 2024, available liquidity under the 2021 and 2023 Credit Facilities totaled approximately $5.3 billion.
Borrowings under the 2021 Credit Facilities and 2023 Credit Facilities may be used for working capital and other general corporate purposes. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 2021 Credit Facilities and 2023 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities and 2023 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required
under its 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.
Subject to each borrower’s sublimit, certain amounts are available for the issuance of LOCs (subject to borrowings drawn under the 2021 Credit Facilities and 2023 Credit Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the 2021 Credit Facilities and 2023 Credit Facilities and against the applicable borrower’s borrowing sublimit. As of December 31, 2024, FirstEnergy had $170 million in outstanding LOCs, $139 million of which are issued under the revolving credit facilities.
The 2021 Credit Facilities and 2023 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the 2021 Credit Facilities and the 2023 Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 2021 Credit Facilities and 2023 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of December 31, 2024, FE was in compliance with its applicable consolidated interest coverage ratio and the borrowers in each case as defined under the 2021 Credit Facilities and 2023 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
2024 2023 2024 2023
For the Years Ended December 31, 5.74 % 6.30 % 6.44 % 6.01 %
Weighted Average Interest Rates
The annual weighted average interest rates on short-term borrowings through the years ended December 31, 2024 and 2023 were 7.10% and 6.96%, respectively.
14. REGULATORY MATTERS
STATE REGULATION
Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
The following table summarizes the key terms of state base rate orders in effect for the Electric Companies as of December 31, 2024:
Company Rates Effective For Customers Allowed Debt/Equity Allowed ROE
CEI May 2009 51%/ 49%
10.5%
FE PA(1)
January 2017 Settled(2)
Settled(2)
MP March 2024 Settled(2)
9.8%
JCP&L June 2024 48.1% / 51.9%
9.6%
OE January 2009 51% /49%
10.5%
PE (West Virginia) March 2024 Settled(2)
9.8%
PE (Maryland) October 2023 47% / 53%
9.5%
TE January 2009 51% / 49%
10.5%
(1) As further discussed below, new rates became effective for customers on January 1, 2025, and did not disclose allowed debt/equity and ROE rates.
(2) Commission-approved settlement agreements did not disclose allowed debt/equity and/or ROE rates.
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 previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally, at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, in accordance with the MDPSC directive, 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. On December 27, 2024, the MDPSC issued an order approving PE’s revised plan. PE recovers EmPOWER program costs with a return on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding. Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025, and 100% in 2026 and beyond. Notwithstanding the order to phase out the unamortized balances of EmPOWER investments, all previously unamortized costs for prior cycles were to be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the unamortized balances was extended through the end of 2030. On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years. On November 27, 2024, PE filed for approval of revised tariff pages reflecting an update of the PE tariff becoming effective in 2025, which included the requested analysis of alternative amortization methods. On December 18, 2024, the MDPSC approved the revised tariff pages permitting PE to continue to use its preferred amortization method. New legislation signed into law on May 9, 2024, and effective July 1, 2024, is expected to reduce the return 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 and 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. The MDPSC and Maryland Office of People’s Counsel filed intents to participate. On November 15, 2024, the parties filed a joint motion to postpone the February 7, 2025 hearing date scheduled by the court and proposed a briefing schedule. The motion was granted on December 28, 2024. PE filed a Petitioner Memorandum on December 17, 2024. The MDPSC and Maryland Office of People’s Counsel filed a Response Memorandum on January 28, 2025. PE filed a Reply Memorandum on February 20, 2025. A hearing is scheduled for 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 base rate increase approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and became effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L was amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.
JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On May 22, 2024, the NJBPU approved JCP&L’s request for a six-month extension of the EE&C Plan I, to December 31, 2024. The budget for the extension period adds approximately $69 million to the original program cost and JCP&L will recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and had a proposed budget of approximately $964 million. EE&C Plan II, as filed, consisted of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. On October 30, 2024, the NJBPU approved the parties’ stipulation of settlement, wherein the parties agreed to a budget of approximately $817 million for EE&C Plan II, including $784 million of investments that will earn a return on equity of 9.6%, with an equity ratio of 52%, and be recovered over 10 years.
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. Orsted’s cancellation does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.
Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the 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.
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base
rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years. JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition.
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 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 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 has scheduled a technical conference for 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 compared to test period revenues, 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 compared to test period revenues 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. The Ohio Companies plan to respond and file supplemental testimony by March 24, 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 July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies proposed that phase two would be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan, which was approved by the PUCO on December 18, 2024 and implementation has since begun. The stipulation provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation, would be completed over a four-year budget period with estimated capital investments of approximately $421 million.
On 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 May 13, 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 May 13, 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 15, "Commitments, Guarantees and Contingencies" below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.
PENNSYLVANIA
On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, 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, as further discussed below.
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 January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On July 22, 2024, FE PA filed its application with the PPUC seeking approval for the next phase of its LTIIP program, which is expected to result in approximately $1.6 billion in investments, with approximately $1.4 billion of such investments going in service during the five-year period beginning January 1, 2025 and ending December 31, 2029. The PPUC approved FE PA’s application on December 19, 2024, and implementation began in January 2025.
On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.
On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requested a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflected a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represented an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing included a proposal to change pension recovery from average cash contributions to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requested an enhanced ten-year vegetation management program and recovery of certain incurred costs, including major storms, COVID-19, a program to convert streetlights to LEDs, and others. On September 13, 2024, FE PA and the active parties to the proceeding filed a joint settlement agreement requesting that the administrative law judges to approve FE PA’s requested distribution base rate case increase subject to the terms and conditions of the settlement, which included, among other things, an annual net revenue increase of $225 million. Other key components of the settlement agreement included recovery of costs incurred for storms and COVID-19, additional cost recovery of ongoing storm costs, inspection and maintenance of overhead lines and transformers, and rate case expenses, as well as an enhanced vegetation management program. On October 15, 2024, the administrative law judges issued a decision recommending that the PPUC approve, without modification, the September 13, 2024 settlement agreement. On November 21, 2024, the PPUC unanimously approved the settlement agreement without modification. New rates became effective on January 1, 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually.
On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, included the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 was to be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing, neither of which occurred. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024. MP and PE will file their next ENEC filing on or before September 1, 2025.
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. The first solar generation site went into service in January 2024 and the second solar generation site went into service in September 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.
On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE were seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and new depreciation rates became effective on April 1, 2024.
On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlements with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.
FERC REGULATORY MATTERS
Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
The following table summarizes the key terms of FERC rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2024:
Company Rates Effective Capital Structure Allowed ROE
ATSI January 2015 Actual (13-month average) 9.88%(1)
JCP&L
January 2020 Actual (13-month average) 10.20%
MP January 2021 Lower of Actual (13-month average) or 56% equity
10.45%
PE January 2021 Lower of Actual (13-month average) or 56% equity
10.45%
KATCo(2)
January 2021 Hypothetical 49.3% equity(3)
10.45%
MAIT July 2017 Lower of Actual (13-month average) or 60% equity
10.3%
TrAIL July 2008 Actual (year-end) 12.7%(4) / 11.7%(5)
(1) Reflects a 0.5% reduction to the 10.38% approved ROE due to the January 2025 Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership (see Transmission ROE Incentive: OCC v. ATSI, et al.)
(2) On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo
(3) Hypothetical capital structure will convert to an actual (13-month average) in January 2027
(4) TrAIL the Line and Black Oak Static Var Compensator
(5) All other projects
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy
had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy has recovered approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements as of December 31, 2024. These reclassifications also resulted in a reduction to the Stand-Alone Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Stand-Alone Transmission segment and on FirstEnergy’s Consolidated Statements of Income. 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 $100 million of certain corporate support costs allocated to distribution capital assets in Ohio.
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, the FERC Office of Enforcement issued a set of data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy responded. The FERC Office of Enforcement issued another set of data requests related to the same fuel consulting contract on January 13, 2025. Responses are due March 5, 2025. 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: OCC v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit. 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. FirstEnergy expects to pursue further appeal. During the fourth quarter of 2024, 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 at the Stand-Alone Transmission segment to reflect the expected refund owed to transmission customers back to February 24, 2022.
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.
Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.
On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.
Local Transmission Planning Complaint: Industrial Energy Consumers of America, et al. v. Avista Corporation, et al.
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 expects to participate in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. 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’s transmission capital investment strategy.
15. COMMITMENTS, GUARANTEES AND CONTINGENCIES
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2024, was approximately $923 million, as summarized below:
Guarantees and Other Assurances Maximum Exposure
(In millions)
FE's Guarantees on Behalf of its Consolidated Subsidiaries(1)
Deferred compensation arrangements $ 406
Vehicle leases 75
Other 14
FE's Guarantees on Other Assurances
Surety Bonds 161
Deferred compensation arrangements 97
LOCs 170
Total Guarantees and Other Assurances $ 923
(1) During the third quarter of 2023, FE was required by PJM to issue a guarantee to cover non-performance until FE PA is able to provide audited financial statements to PJM, which is expected to occur in early 2025. The guarantee is expected to be immaterial to FE.
COLLATERAL AND CONTINGENT-RELATED FEATURES
In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
As of December 31, 2024, $170 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $29 million of net cash collateral as of December 31, 2024, from certain generation suppliers, and such amount is included in "Other current liabilities" on FirstEnergy's Consolidated Balance Sheets.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2024:
Potential Collateral Obligations Electric Companies and Transmission Companies FE Total
(In millions)
Contractual Obligations for Additional Collateral
Upon Further Downgrade $ 77 $ 1 $ 78
Surety Bonds (collateralized amount)(1)
97 49 146
Total Exposure from Contractual Obligations $ 174 $ 50 $ 224
(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 obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.
Clean Air Act
FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.
Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the
Good Neighbor Plan with the U.S. Supreme Court. Oral argument was heard on February 21, 2024. On June 27, 2024, the U.S. Supreme Court granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. 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.
Climate Change
In recent years, regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. 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). Our ability to achieve our GHG reduction goal is subject to our ability to make operational changes and is conditioned upon numerous risks, many of which are outside of our control. With respect to our coal-fired plants in West Virginia, which serve as the primary source of our Scope 1 emissions, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. FirstEnergy cannot currently estimate the financial impact of climate change policies, including the final SEC climate disclosure rules, which are currently stayed, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule 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 U.S. Supreme Court. On October 16, 2024, the U.S. Supreme Court 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. Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft. Martin and Harrison power stations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the 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 and will be reviewed by the U.S. Court of Appeals for the Eighth Circuit Court. On October 10, 2024, the Eighth Circuit denied the motions for stay. Depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. As of December 31, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station. During the second quarter of 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 and corresponding increase to “Other operating expense” of $87 million at Corporate/Other for segment reporting. On February 3, 2025, AE Supply executed an environmental liability transfer agreement with a subsidiary of IDA Power, LLC, whereby AE Supply will transfer the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations. The agreement requires AE Supply to establish a $160 million escrow account that AE Supply will fund over five years. The escrow funding obligation will be secured by a surety bond, which will be guaranteed by FE. The transaction is expected to close before the end of the first quarter of 2025 and the derecognition of the ARO is not expected to have a material impact to FirstEnergy’s financial statements, however, no assurances of the closing of the transfer will be satisfied, including transfer of all required environmental permits.
On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. Depending on the outcome of appeals and the ultimate implementation of the final rule, compliance with these standards could require remedial actions, including removal of coal ash. See Note 8, “Asset Retirement Obligations,” above for a description of the $139 million increase to its ARO that FirstEnergy recorded during 2024 as a result of its analysis.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often
unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of December 31, 2024 based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $98 million have been accrued through December 31, 2024, of which approximately $69 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
United States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the U.S. Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District 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 United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 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 January 17, 2025, indictment. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information.
Legal Proceedings Relating to United States v. Larry Householder, et al.
On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers relating to the conduct described in the DPA. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. FirstEnergy cooperated fully with the SEC investigation, and on September 12, 2024, the SEC issued a settlement order that concluded and resolved the investigation in its entirety. Under the terms of the settlement, FE agreed to pay a civil penalty of $100 million and to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder, which was recognized as a loss contingency of $100 million in the second quarter of 2024 at Corporate/Other for segment reporting and paid on September 25, 2024.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understood that the OOCIC’s investigation was also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and
aggravated theft, related to payments described in the DPA. On August 12, 2024, FirstEnergy entered into a settlement with the OAG's Office and the Summit County Prosecutor’s Office to resolve both the OOCIC investigation and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp., noted below. The settlement includes, among other things, a non-prosecution agreement and a payment of $19.5 million, which was recorded as a loss contingency in the second quarter of 2024 in FirstEnergy’s Consolidated Statements of Income at Corporate/Other for segment reporting and was paid on August 16, 2024.
In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing 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 of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order; the Sixth Circuit granted FE’s petition on November 16, 2023, and 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 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.
•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills included new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the case in light of the February 9, 2024, indictments against defendants in this action, which the court granted on March 14, 2024. As described above, FE reached a settlement with the OAG of this civil action and the OOCIC investigation, which resolves this civil action. FE recognized a loss contingency of $19.5 million in the second quarter of 2024, which was paid on August 16, 2024.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.
•Miller v. Anderson, et al. (N.D. Ohio); on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon the approval of the settlement by the S.D. Ohio, which was granted on May 17, 2024.
•Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); on September 1, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022, which was appealed by a purported FE stockholder on June 15, 2023. The U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. All appeal options were exhausted on May 16, 2024.
The above settlement included a series of corporate governance enhancements and a payment to FE of $180 million, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs, and a $7 million net return on deposited funds, which was received in the second quarter of 2024. The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.
The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 13, “Regulatory Matters.”
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations, and cash flows.
16. SEGMENT INFORMATION
During the first quarter of 2024, FirstEnergy’s segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. FirstEnergy’s reportable segments are as follows, and FirstEnergy continues to evaluate segment performance based on earnings attributable to FE from continuing operations:
•Distribution Segment, which consists of the Ohio Companies and FE PA;
•Integrated Segment, which consists of MP, PE and JCP&L; and
•Stand-Alone Transmission Segment, which consists of FE's ownership in FET and KATCo.
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission.
The segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. In
accordance with GAAP, the modification to the segments in the first quarter of 2024 resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chair, President and Chief Executive Officer, its CODM. FirstEnergy's CODM uses earnings attributable to FE from continuing operations to assess performance and considers budget versus actual results on a monthly basis when making decisions about allocating resources to the segments. Disclosures for FirstEnergy's reportable operating segments for 2023 and 2022 have been reclassified to conform to the current presentation reflecting the new reportable segments.
The Distribution segment, which consists of the Ohio Companies and FE PA, 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 January and September 2024, representing 24 MWs of net maximum generating capacity. The remaining three sites, once completed, are expected to provide 26 MWs of additional 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. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains in the Stand-Alone Transmission segment. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and prior year results in the Stand-Alone Transmission segment reflect the earnings and results of those WP transmission assets.
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 December 31, 2024, Corporate/Other had approximately $6.1 billion of external FE holding company debt.
Financial information for FirstEnergy’s business segments and reconciliations to consolidated amounts is presented below:
(In millions) Distribution Integrated Stand-Alone Transmission Total Reportable Segments Corporate/Other Reconciling Adjustments FirstEnergy Consolidated
For the Years Ended
December 31, 2024
External revenues $ 6,824 $ 4,871 $ 1,768 $ 13,463 $ 9 $ - $ 13,472
Internal revenues 39 5 19 63 - (63) -
Total revenues $ 6,863 $ 4,876 $ 1,787 $ 13,526 $ 9 $ (63) $ 13,472
Other operating expenses(1)
2,408 1,324 359 4,091 78 (10) 4,159
Depreciation(1)
648 521 336 1,505 76 - 1,581
Amortization (deferral) of regulatory assets, net (171) (66) 6 (231) - - (231)
Equity method investment earnings, net - - - - 58 - 58
Interest expense(1)
432 262 275 969 360 (185) 1,144
Income taxes (benefits)(1)
135 153 173 461 (84) - 377
Other expense (income) items(2)
2,787 2,147 344 5,278 59 185 5,522
Earnings (losses) attributable to FE from continuing operations 624 535 294 1,453 (475) - 978
Cash Flows from Investing Activities
Capital investments $ 1,130 $ 1,542 $ 1,266 $ 3,938 $ 92 $ - $ 4,030
December 31, 2023
External revenues $ 6,813 $ 4,315 $ 1,731 $ 12,859 $ 11 $ - $ 12,870
Internal revenues 41 5 17 63 - (63) -
Total revenues $ 6,854 $ 4,320 $ 1,748 $ 12,922 $ 11 $ (63) $ 12,870
Other operating expenses(1)
2,129 1,156 338 3,623 (19) (10) 3,594
Depreciation(1)
620 462 304 1,386 75 - 1,461
Amortization (deferral) of regulatory assets, net (259) (10) 8 (261) - - (261)
Equity method investment earnings, net - - - - 175 - 175
Interest expense(1)
390 257 245 892 340 (108) 1,124
Income taxes (benefits)(1)
147 37 146 330 (63) - 267
Other expense (income) items(2)
3,240 2,118 308 5,666 (37) 108 5,737
Earnings (losses) attributable to FE from continuing operations 587 300 399 1,286 (163) - 1,123
Cash Flows from Investing Activities
Capital investments $ 936 $ 1,212 $ 1,093 $ 3,241 $ 115 $ - $ 3,356
December 31, 2022
External revenues $ 6,386 $ 4,465 $ 1,581 $ 12,432 $ 27 $ - $ 12,459
Internal revenues 39 5 16 60 - (60) -
Total revenues $ 6,425 $ 4,470 $ 1,597 $ 12,492 $ 27 $ (60) $ 12,459
Other operating expenses(1)
2,094 1,226 428 3,748 79 (10) 3,817
Depreciation(1)
593 430 277 1,300 75 - 1,375
Amortization (deferral) of regulatory assets, net (241) (128) 4 (365) - - (365)
Equity method investment earnings, net - - - - 168 - 168
Interest expense(1)
325 225 263 813 354 (128) 1,039
Income taxes (benefits)(1)
202 80 111 393 607 - 1,000
Other expense (income) items(2)
2,778 2,372 199 5,349 (122) 128 5,355
Earnings (losses) attributable to FE from continuing operations 674 265 315 1,254 (848) - 406
Cash Flows from Investing Activities
Capital investments $ 925 $ 998 $ 874 $ 2,797 $ 51 $ - $ 2,848
As of December 31, 2024
Total Assets $ 19,949 $ 18,637 $ 13,528 $ 52,114 $ 1,975 $ (2,045) $ 52,044
Total Goodwill(3)
$ 3,222 $ 1,953 $ 443 $ 5,618 $ - $ - $ 5,618
As of December 31, 2023
Total Assets $ 19,235 $ 17,466 $ 12,142 $ 48,843 $ 2,372 $ (2,448) $ 48,767
Total Goodwill(3)
$ 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, Debt redemption costs, Miscellaneous income, net, Capitalized financing costs, Pension and OPEB mark-to-market adjustments, and Income attributable to noncontrolling interest.
(3) In accordance with GAAP, the modification to the segments in the first quarter of 2024, as discussed above, resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
FirstEnergy, through the oversight of its Disclosure Committee, has established disclosure controls and procedures to ensure that information is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure, and ensure that information required to be disclosed in the reports FirstEnergy files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.
The management of FirstEnergy, with the participation of the chief executive officer and chief financial officer, has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of December 31, 2024. Based on that evaluation, the chief executive officer and chief financial officer of FirstEnergy have concluded that its disclosure controls and procedures were effective as of December 31, 2024.
Management’s Report on Internal Control over Financial Reporting
Management of FirstEnergy is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. FirstEnergy’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting as of December 31, 2024, based on the framework in "Internal Control-Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2024.
The effectiveness of FirstEnergy’s internal control over financial reporting as of December 31, 2024 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2024, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
Trading Arrangements
During the quarter ended December 31, 2024, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of FE adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408 of Regulation S-K).

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 is incorporated herein by reference to FirstEnergy's 2025 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
FirstEnergy has adopted an insider trading compliance policy regarding securities transactions (the "Insider Trading Practice") that applies to its directors, officers, employees, consultants, and contractors and our subsidiaries, as well as the company itself. FirstEnergy believes that the Insider Trading Compliance Practice is reasonably designed to promote compliance with insider trading laws, rules and regulations with respect to the purchase, sale and/or other dispositions of FirstEnergy’s securities, as well as the applicable rules and regulations of the New York Stock Exchange. A copy of the Insider Trading Practice is filed as Exhibit 19 to this Annual Report on Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2025 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The Item 403 of Regulation S-K information required by Item 12 is incorporated herein by reference to FirstEnergy's 2025 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
The following table contains information as of December 31, 2024, regarding compensation plans for which shares of FE common stock may be issued.
Plan category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in First Column)
Equity compensation plans approved by security holders 4,428,103 (1) $ - (2) 8,529,960 (3)
Equity compensation plans not approved by security holders(4)
- $ - -
Total 4,428,103 $ - 8,529,960
(1) Includes 256,061 shares related to the DCPD that is expected to be paid in stock, 2,086,021 shares subject to outstanding awards of stock based Restricted Stock Units granted under the ICP 2020 if paid at target for the 2022-2024, 2023-2025, and 2024-2026 cycles of stock based Restricted Stock Units, as well as 2,086,021 additional shares to be paid if maximum performance metrics are achieved for the three outstanding cycles.
(2) There are no outstanding options, therefore, no consideration is required from participants for the exercise or vesting of any outstanding equity compensation awards.
(3) Additional shares may become available due to cancellations, forfeitures, cash settlements or other similar circumstances with respect to outstanding awards.
(4) All equity compensation plans have been approved by FE's shareholders.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated herein by reference to FirstEnergy’s 2025 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
A summary of the audit and all other fees for services rendered by PricewaterhouseCoopers LLP are as follows:
For the Years Ended December 31,
2024 2023
(In thousands)
Audit Fees(1)
$ 11,235 $ 9,915
Audit-Related Fees(2)
60 -
Tax Fees(3)
110 110
All Other Fees(4)
48 282
Total Fees $ 11,453 $ 10,307
(1) Professional services rendered for the audits of FirstEnergy's and certain of its subsidiary annual financial statements and reviews of unaudited financial statements included in FirstEnergy's Quarterly Reports on Form 10-Q filings made with the SEC, and for services in connection with statutory and regulatory filings or engagements, including comfort letters, agreed upon procedures and consents for financings. 2024 and 2023 audit fees also include newly required regulatory audits for certain subsidiaries and additional audit services to support the registration of certain subsidiaries with the SEC during 2024.
(2) Audit-related fees in 2024 were related to services rendered for climate-related reporting assessments.
(3) Tax fees in 2024 and 2023 were primarily related to the performance of tax services related to the FET equity interest sales.
(4) All other fees in 2024 and 2023 primarily reflect certain costs related to the SEC investigation.
Additional information required by this item is incorporated herein by reference to FirstEnergy’s 2025 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report on Form 10-K:
1. Financial Statements:
Management’s Report on Internal Control Over Financial Reporting for FirstEnergy Corp. is listed under Item 9A, "Controls and Procedures" herein.
Report of Independent Registered Public Accounting Firm (PCAOB ID 238) for FirstEnergy Corp. is listed under Item 8, "Financial Statements and Supplementary Data," herein.
The financial statements filed as a part of this report for FirstEnergy Corp. are listed under Item 8, "Financial Statements and Supplementary Data," herein.
2. Financial Statement Schedules:
N/A - Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.
3. Exhibits
Exhibit
Number
3.1 Amended and Restated Articles of Incorporation of FirstEnergy Corp. (incorporated by reference to FE’s Form 10-Q filed July 23, 2019, Exhibit 3-1, File No. 333-21011).
3.2 Third Amended and Restated Code of Regulations of FirstEnergy Corp., effective May 17, 2022 (incorporated by reference to FE’s Form 8-K on May 23, 2022, Exhibit 3.1, File No. 333-21011).
3.3 Amendment to the Third Amended and Restated Code of Regulations (incorporated by reference to FE’s Form 10-Q filed August 1, 2023, Exhibit 3.1, File No. 333-21011).
4.1 Indenture, dated November 15, 2001, between FirstEnergy Corp. and The Bank of New York Mellon, as Trustee (incorporated by reference to FE’s Form S-3 filed September 21, 2001, Exhibit 4(a), File No. 333-69856).
4.2 Indenture, dated as of May 4, 2023, between FirstEnergy Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee. (incorporated by reference to FirstEnergy’s Form 8-K filed May 4, 2023, Exhibit 4.1, File No. 333-21011)
Exhibit
Number
4.3 Officer’s Certificate relating to FirstEnergy Corp.'s 2.85% Notes, Series A, due 2022, 3.90% Notes, Series B, due 2027 and 4.85% Notes, Series C, due 2047 (incorporated by reference to FE’s Form 8-K filed June 21, 2017, Exhibit 4.1, File No. 333-21011).
4.4 Form of 3.90% Note, Series B, due 2027 (incorporated by reference to FE’s Form 8-K filed June 21, 2017, Exhibit 4.1, File No. 333-21011).
4.5 Form of 4.85% Note, Series C, due 2047 (incorporated by reference to FE’s Form 8-K filed June 21, 2017, Exhibit 4.1, File No. 333-21011).
4.6 Officer’s Certificate relating to FirstEnergy Corp.'s 2.050% Notes, Series A, due 2025, 2.650% Notes, Series B, due 2030 and 3.400% Notes, Series C, due 2050 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.1, File No. 333-21011).
4.7 Form of 2.050% Note, Series A, due 2025 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.2, File No. 333-21011).
4.8 Form of 2.650% Note, Series B, due 2030 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.3, File No. 333-21011).
4.9 Form of 3.400% Note, Series C, due 2050 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.4, File No. 333-21011).
4.10 Officer’s Certificate relating to FirstEnergy Corp.'s 1.600% Notes, Series A, due 2026, 2.250% Notes, Series B, due 2030 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.1, File No. 333-21011).
4.11 Form of 1.600% Note, Series A, due 2026 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.2, File No. 333-21011).
4.12 Form of 2.250% Note, Series B, due 2030 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.3, File No. 333-21011).
4.13 Description of Securities Registered under Section 12(b) of the Securities Exchange Act of 1934 (incorporated by reference to FE's Form 10-K filed February 10, 2020, Exhibit 4-10, File No. 333-21011).
4.14 Form of 4.00% Convertible Senior Notes due 2026 (included hereto in Exhibit 4.2)
10.1 Credit Agreement, dated as of October 18, 2021, by and among FirstEnergy Corp., FirstEnergy Transmission, LLC, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FE’s Form 8-K filed October 18, 2021, Exhibit 10.1, File No. 333-210111).
10.2 Credit Agreement, dated as of October 18, 2021, by and among The Cleveland Electric Illuminating Company, Ohio Edison Company, The Toledo Edison Company, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.2, File No. 333-21011).
10.3 Credit Agreement, dated as of October 18, 2021, by and among Metropolitan Edison Company, Pennsylvania Power Company, Pennsylvania Electric Company, West Penn Power Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.3, File No. 333-21011).
10.4 Credit Agreement, dated as of October 18, 2021, by and among Jersey Central Power & Light Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.4, File No. 333-21011).
10.5 Credit Agreement, dated as of October 18, 2021, by and among American Transmission Systems, Incorporated, Mid-Atlantic Interstate Transmission, LLC, and Trans-Allegheny Interstate Line Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and PNC Bank, National Association, as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.5, File No. 333-21011).
10.6 Credit Agreement, dated as of October 18, 2021, by and among Monongahela Power Company, The Potomac Edison Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd, as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.6, File No. 333-21011).
10.7 Amendment No. 1 and Consent and Limited Waiver to Credit Agreement, dated as of April 27, 2023, by and among FirstEnergy Corp., FirstEnergy Transmission, LLC, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent. (incorporated by reference to FirstEnergy’s Form 8-K filed May 1, 2023, Exhibit 10.1, File No. 333-21011)
10.8 Amendment No. 1 and Consent and Limited Waiver to Credit Agreement, dated as of April 27, 2023, by and among The Cleveland Electric Illuminating Company, Ohio Edison Company, The Toledo Edison Company, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent. (incorporated by reference to FirstEnergy’s Form 8-K filed May 1, 2023, Exhibit 10.2, File No. 333-21011)
10.9 Amendment No. 1 and Consent and Limited Waiver to Credit Agreement, dated as of April 27, 2023, by and among Metropolitan Edison Company, Pennsylvania Power Company, Pennsylvania Electric Company, West Penn Power Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent. (incorporated by reference to FirstEnergy’s Form 8-K filed May 1, 2023, Exhibit 10.3, File No. 333-21011)
10.10 Amendment No. 1 and Consent and Limited Waiver to Credit Agreement, dated as of April 27, 2023, by and among American Transmission Systems, Incorporated, Mid-Atlantic Interstate Transmission, LLC, Trans-Allegheny Interstate Line Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and PNC Bank, National Association, as administrative agent. (incorporated by reference to FirstEnergy’s Form 8-K filed May 1, 2023, Exhibit 10.4, File No. 333-21011)
Exhibit
Number
10.11 Amendment No. 1 to Credit Agreement, dated as of April 27, 2023, by and among Jersey Central Power & Light Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent. (incorporated by reference to FirstEnergy’s Form 8-K filed May 1, 2023, Exhibit 10.5, File No. 333-21011)
10.12 Amendment No. 1 to Credit Agreement, dated as of April 27, 2023, by and among Monongahela Power Company, The Potomac Edison Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd, as administrative agent. (incorporated by reference to FirstEnergy’s Form 8-K filed May 1, 2023, Exhibit 10.6, File No. 333-21011)
10.13 Amendment No. 2 and Consent and Limited Waiver to Credit Agreement, dated as of October 20, 2023, by and among FirstEnergy Corp., the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.1, File No. 333-21011).
10.14 Amendment No. 2 and Consent and Limited Waiver to Credit Agreement, dated as of October 20, 2023, by and among The Cleveland Electric Illuminating Company, Ohio Edison Company, The Toledo Edison Company, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.2, File No. 333-21011).
10.15 Amendment No. 2 and Consent and Limited Waiver to Credit Agreement, dated as of October 20, 2023, by and among Metropolitan Edison Company, Pennsylvania Power Company, Pennsylvania Electric Company, West Penn Power Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.3, File No. 333-21011).
10.16 Amendment No. 2 and Consent and Limited Waiver to Credit Agreement, dated as of October 20, 2023, by and among American Transmission Systems, Incorporated, Mid-Atlantic Interstate Transmission, LLC, Trans-Allegheny Interstate Line Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and PNC Bank, National Association, as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.4, File No. 333-21011).
10.17 Amendment No. 2 to Credit Agreement, dated as of October 20, 2023, by and among Jersey Central Power & Light Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.5, File No. 333-21011).
10.18 Amendment No. 2 to Credit Agreement, dated as of October 20, 2023, by and among Monongahela Power Company, The Potomac Edison Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd, as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.6, File No. 333-21011).
10.19 Credit Agreement, dated as of October 20, 2023, by and among Keystone Appalachian Transmission Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and PNC Bank, National Association, as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.7, File No. 333-21011).
10.20 Credit Agreement, dated as of October 20, 2023, by and among FirstEnergy Transmission, LLC, the banks and other financial institutions party thereto on the date hereof, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent. (incorporated by reference to FE’s Form 10-Q filed October 26, 2023, Exhibit 10.8, File No. 333-21011).
10.21 Amendment No. 3 to Credit Agreement, dated as of October 24, 2024, among FE, as borrower, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.2, File No. 333-21011)
10.22 Amendment No. 3 to Credit Agreement, dated as of October 24, 2024, among CEI, OE and TE, as borrowers, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.3, File No. 333-21011)
10.23 Amendment No. 3 to Credit Agreement, dated as of October 24, 2024, among FE PA, as borrower, the banks and other financial institutions party thereto, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.4, File No. 333-21011)
10.24 Amendment No. 3 to Credit Agreement, dated as of October 24, 2024, among JCP&L, as borrower, the banks and other financial institutions party thereto, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.5, File No. 333-21011)
10.25 Amendment No. 3 to Credit Agreement, dated as of October 24, 2024, among MP and PE, the banks and other financial institutions party thereto, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.6, File No. 333-21011)
10.26 Amendment No. 3 to Credit Agreement, dated as of October 24, 2024, among ATSI, MAIT and TrAIL, as borrower, the banks and other financial institutions party thereto, as lenders, and PNC Bank, National Association, as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.7, File No. 333-21011)
10.27 Amendment No. 1 to Credit Agreement and Consent, dated as of October 24, 2024, among FET, as borrower, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.8, File No. 333-21011)
10.28 Amendment No. 1 to Credit Agreement, dated as of October 24, 2024, among KATCo, as borrower, the banks and other financial institutions party thereto, as lenders, and PNC Bank, National Association, as administrative agent (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.9, File No. 333-21011)
10.29 Consent Decree dated March 18, 2005 (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10-1, File No. 333-21011).
Exhibit
Number
10.30 Settlement Agreement, dated as of August 26, 2018, by and among the Debtors, the FE Non-Debtor Parties, the Ad Hoc Noteholders Group, the Bruce Mansfield Certificateholders Group and the Committee (in each case, as defined therein) (incorporated by reference to FE’s Form 8-K filed August 27, 2018, Exhibit 10.1, File No. 333-21011).
10.31 Deferred Prosecution Agreement, dated as of July 21, 2021 (incorporated by reference to FE’s Form 8-K filed July 22, 2021, Exhibit 10.1, File No. 333-21011).
10.32 Agreement between the Office of the Ohio Attorney General, the Office of the Summit County Prosecutor and FirstEnergy Corp. dated August 12, 2024 (incorporated by reference to FE’s Form 8-K filed August 13, 2024, Exhibit 99.2, File No. 333-21011).
10.33 Settlement Order, dated as of September 12, 2024 (incorporated by reference to FE’s Form 8-K filed September 12, 2024, Exhibit 99.2, File No. 333-21011).
10.34 Purchase and Sale Agreement, dated as of November 6, 2021, among the FirstEnergy Corp. and North American Transmission Company II LLC, and Brookfield Super-Core Infrastructure Partners L.P., Brookfield Super-Core Infrastructure Partners (NUS) L.P. and Brookfield Super-Core Infrastructure Partners (ER) SCSp, as guarantors. (incorporated by reference to FE’s Form 10-K filed February 16, 2022, Exhibit 10-10, File No. 333-21011).
10.35 Purchase and Sale Agreement, dated as of February 2, 2023, among the FirstEnergy Corp., and FirstEnergy Transmission, LLC, and North American Transmission Company II L.P., and North American Transmission FINCO L.P., Brookfield Super-Core Infrastructure Partners L.P., Brookfield Super-Core Infrastructure Partners (NUS) L.P. and Brookfield Super-Core Infrastructure Partners (ER) SCSp, as guarantors. (incorporated by reference to FE’s Form 10-Q filed April 27, 2023, Exhibit 10.1, File No. 333-21011).
10.36 Fourth Amended and Restated Limited Liability Company Agreement of FirstEnergy Transmission, LLC, dated March 25, 2024 (incorporated by reference to FE’s Form 8-K filed March 25, 2024, Exhibit 10.1, File No. 333-21011).
10.37 Common Stock Purchase Agreement, dated as of November 6, 2021, among the FirstEnergy Corp. and BIP Securities II-B L.P. (incorporated by reference to FE’s Form S-3 filed on December 13, 2021, Exhibit 4(d), File No. 333-210111).
10.38 (B) FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated January 1, 2005, further amended December 31, 2010 (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-6, File No. 333-21011).
10.39 (B) Amendment No. 1 to Deferred Compensation Plan for Outside Directors, effective as of January 1, 2012 (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.7, File No. 333-21011).
10.40 (B) Amendment No. 2 to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, effective January 21, 2014, (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-8, File No. 333-21011).
10.41 (B) Amendment No. 3 to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, dated January 14, 2019 and effective as of April 1, 2018 (incorporated by reference to FE's Form 10-K filed February 19, 2019, Exhibit 10-7, File No.333-21011).
10.42 (B) FirstEnergy Corp. Supplemental Executive Retirement Plan, amended and restated January 1, 2005, further amended December 31, 2010 (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-9, File No. 333-21011).
10.43 (B) Amendment No. 1 to FirstEnergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2012 (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.8, File No. 333-21011).
10.44 (B) Amendment No. 2 to FirstEnergy Corp. Supplemental Executive Retirement Plan, dated January 14, 2019 and effective as of April 1, 2018 (incorporated by reference to FE's Form 10-K filed February 19, 2019, Exhibit 10-10, File No. 333-21011).
10.45 (B) FirstEnergy Corp. Cash Balance Restoration Plan, effective January 1, 2014 (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-11, File No. 333-21011).
10.46 (B) Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000 (incorporated by reference to GPU, Inc. Form 10-K filed March 21, 2001, Exhibit 10-N, File No. 001-06047).
10.47 (B) Allegheny Energy, Inc. Non-Employee Director Stock Plan (incorporated by reference to FE's Form 8-K filed February 25, 2011, Exhibit 10.4, File No. 21011).
10.48 (B) Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of Directors (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-29, File No. 333-21011).
10.49 (B) Amendment No. 1 to Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of Directors (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-30, File No. 333-21011).
10.50 (B) Form of Director and Officer Indemnification Agreement (incorporated by reference to FE’s Form 8-K filed May 16, 2018, Exhibit 10.1, File No. 333-21011).
10.51 (B) Guarantee, dated as of September 16, 2013 by FirstEnergy Corp. in favor of participants under the FirstEnergy Corp. Executive Deferred Compensation Plan (incorporated by reference to FE’s Form 10-Q filed November 5, 2013, Exhibit 10.2, File No. 333-21011).
10.52 (B) FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated July 20, 2015, and effective as of November 1, 2015 (incorporated by reference to FE's Form 8-K filed July 24, 2015, Exhibit 10.1, File No. 333-21011).
10.53 (B) Amendment No. 1 to FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated January 14, 2019 and effective as of April 1, 2018 (incorporated by reference to FE's Form 10-K filed February 19, 2019, Exhibit 10-23, File No. 333-21011).
10.54 (B) FirstEnergy Corp. 2017 Change in Control Severance Plan, dated as of September 15, 2015, and effective as of January 1, 2017 (incorporated by reference to FE's Form 8-K filed September 18, 2015, Exhibit 10.1, File No. 333-21011).
10.55 (B) Waiver of Participation in the FirstEnergy Corp. Change in Control Severance Plan, entered into by Charles E. Jones dated as of September 15, 2015 (incorporated by reference to FE's Form 8-K filed September 18, 2015, Exhibit 10.2, File No. 333-21011).
Exhibit
Number
10.56 (B) Non-Competition and Non-Disparagement Agreement, entered into by Charles E. Jones, dated as of September 15, 2015 (incorporated by reference to FE's Form 8-K filed September 18, 2015, Exhibit 10.3, File No. 333-21011).
10.57 (B) FirstEnergy Corp. 2015 Incentive Compensation Plan (incorporated by reference to FE's Definitive Proxy Statement filed April 1, 2015, Appendix A, File No. 333-21011).
10.58 (B) Amendment No. 1 to the FirstEnergy Corp. 2015 Incentive Compensation Plan, effective February 21, 2017 (incorporated by reference to FE's Form 10-K filed February 21, 2017, Exhibit 10-51, File No. 333-21011).
10.59 (B) Executive Severance Benefits Plan, as amended and restated as of December 20, 2016 (incorporated by reference to FE’s Form 8-K filed December 21, 2016, Exhibit 10.1, File No. 333-21011).
10.60 (B) Amendment No. 2 to FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated September 18, 2019 and effective as of November 1, 2015 (incorporated by reference to FE's Form 10-Q filed November 4, 2019, Exhibit 10.3, File No.333-21011).
10.61 (B) Guarantee, dated as of February 21, 2017, by FirstEnergy Corp. in favor of participants under the FirstEnergy Corp. Cash Balance Pension Restoration Plan (incorporated by reference to FE’s Form 10-Q filed July 27, 2017, Exhibit 10.1, File No. 333-21011).
10.62 (B) FirstEnergy Solutions Corp. Voluntary Enhanced Retirement Option, effective as of January 2, 2019 (incorporated by reference to FE’s Form 8-K filed November 21, 2018, Exhibit 10.1, File No. 333-21011).
10.63 Consent and Waiver to the Settlement Agreement, dated April 18, 2019, by and among the Debtors and the FE Non-Debtor Parties (incorporated by reference to FE's Form 10-Q filed April 23, 2019, Exhibit 10.1, File No.333-21011).
10.64 First Amendment to Settlement Agreement dated November 21, 2019, by and among the Debtors, FE Non-Debtor Parties, Ad Hoc Noteholders Group, Bruce Mansfield Certificateholders Group, and the Committee (incorporated by reference to FE’s Form 8-K filed November 26, 2019, Exhibit 10.1, File No. 333-21011).
10.65 (B) Form of 2020 Restricted Stock Award Agreement (incorporated by reference to FE's Form 10-Q filed April 23, 2020, Exhibit 10.3, File No.333-21011).
10.66 (B) FirstEnergy Corp. 2020 Incentive Compensation Plan (incorporated by reference to FE's Form 8-K filed May 20, 2020, Exhibit 10.1, File No.333-21011).
10.67 (B) Form of Restricted Stock Award Agreement (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.3, File No. 333-21011).
10.68 (B) Restricted Stock Award Agreement to John W. Somerhalder II (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.5, File No. 333-21011).
10.69 (B) Form of 2022-2024 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 21, 2022, Exhibit 10.1, File No. 333-21011).
10.70 (B) Form of 2022-2024 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 21, 2022, Exhibit 10.2, File No. 333-21011).
10.71 (B) Form of 2023-2025 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed August 1, 2023, Exhibit 10.7, File No. 333-21011).
10.72 (B) Form of 2023-2025 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed August 1, 2023, Exhibit 10.8, File No. 333-21011).
10.73 (B) Form of 2024-2026 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 25, 2024, Exhibit 10.2, File No. 333-21011).
10.74 (B) Form of 2024-2026 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 25, 2024, Exhibit 10.3, File No. 333-21011).
10.75 (B) Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement to John W. Somerhalder II (incorporated by reference to FE’s Form 10-Q filed July 26, 2022, Exhibit 10.3, File No. 333-21011).
10.76 (B) Offer letter, dated March 26, 2023, between FirstEnergy Corp. and Brian X. Tierney (incorporated by reference to FE’s Form 10-Q filed April 27, 2023, Exhibit 10.2, File No. 333-21011).
10.77 (B) 2022 Interim Chief Executive Officer Restricted Stock Units Award Agreement to John W. Somerhalder II. (incorporated by reference to FE’s Form 10-K filed February 13, 2023, Exhibit 10.59, File No. 333-21011).
10.78 (B) 2023 Interim Chief Executive Officer Restricted Stock Units Award Agreement to John W. Somerhalder II. (incorporated by reference to FE’s Form 10-K filed February 13, 2023, Exhibit 10.60, File No. 333-21011).
10.79 (B) Severance Agreement and Release of Claims of Christine L. Walker (incorporated by reference to FE’s Form 10-Q filed October 29, 2024, Exhibit 10.1, File No. 333-21011).
14 Code of Business Conduct and Ethics (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 14.1, File No. 333-21011).
19 (A) Insider Trading Practice
21 (A) List of Subsidiaries of the Registrant at December 31, 2024.
23 (A) Consent of Independent Registered Public Accounting Firm.
31.1 (A) Certification of chief executive officer, pursuant to Rule 13a-14(a).
31.2 (A) Certification of chief financial officer, pursuant to Rule 13a-14(a).
32 (A) Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
97 Policy relating to recovery of erroneously awarded compensation (incorporated by reference to FE’s Form 10-K filed February 13, 2024, Exhibit 97, File No. 333-21011).
Exhibit
Number
101 The following materials from the Annual Report on Form 10-K for FirstEnergy Corp. for the period ended December 31, 2024, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Common Stockholders' Equity, (v) Consolidated Statements of Cash Flows, (vi) 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)
(A) Provided herein in electronic format as an exhibit.
(B) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FirstEnergy has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.