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YoY shift: Neutral
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.05pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.07pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.04pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
penalties+2
shortages+2
threats+2
impairments+2
exploit+2
Positive rising
efficiency+1
successful+1
despite+1
positive+1
success+1
Risk Factors (Item 1A)
13,017 words
ITEM 1A. RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond the Registrants’ control. The Registrants regularly evaluate the most significant risks of their businesses and review those risks with their respective boards of directors and, if appropriate, committees of those boards of directors. The following risk factors and all other information contained in this report should be considered carefully when evaluating the Registrants, and unless a risk factor expressly excludes a Registrant or the context requires otherwise, references to “we,” “us,” and “our” refer to both Registrants. 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.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
absence+29
impairment+11
endangerment+6
litigation+5
unable+4
Positive rising
benefit+10
stable+3
good+1
attain+1
progress+1
MD&A (Item 7)
38,167 words
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 the Registrants’ management and unless the context requires otherwise, references to “we,” “us,” “our” and “FirstEnergy” refer to the Registrants collectively. 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 and agreements, including those associated with compliance with or to comply with the DPA, and settlements with the OAG's office and the SEC;
Risks Associated with Damage to Our Reputation and Securities Class-Action Litigation
Securities class-action litigationagainst us 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, FE 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, criminalprosecution 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, criminalprosecution, 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 indictmentagainst two former FirstEnergy senior officers, described in “Outlook—Other Legal Proceeding – United States v. Larry Householder, et al.,” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations". Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information. On February 26, 2025, the U.S. Attorney’s Office filed a status report confirming these commitments.
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 allegedfailures 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 FE’s 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.
This securities class-action litigation 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 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 14, "Commitments, Guarantees and Contingencies,” of the Combined Notes to Financial Statements of the Registrants 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 14., “Commitments, Guarantees and Contingencies,” of the Combined Notes to Financial Statements of the Registrants, for additional details on the government investigations and subsequent litigation surrounding HB 6.
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 towards maintaining new and ongoing positive relationships with customers, regulators, investors, and other stakeholders. 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, among other things, changes in our service reliability, our rate affordability or negative outcomes in the ongoing matters relating to HB 6, 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 and the Regulation of Our Distribution and Transmission Businesses
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, deploying advanced technology, including but not limited to artificial intelligence, 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 unexpecteddelays 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.
Our ability to grow our distribution and transmission businesses is subject to numerous risks and events, many of which are outside of our control.
The success of our growth strategy will depend, in part, on the successful growth of revenue resulting from our transmission investments in line with our expectations. Factors that may affect our revenue growth may include: (1) FERC’s timely approval of rates to recover such investments; (2) whether investments are included in PJM's RTEP; (3) FERC's evolving policies with respect to incentive rates for transmission investment assets, the calculation of the base ROE component of transmission rates, and the interconnection of AI data centers and transmission network upgrades supporting such large loads; (4) FERC’s potentially-evolving policies regarding whether certain classes of network transmission upgrade costs can be capitalized as part of transmission rates and whether such costs will be direct charged to the connecting customer; (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. Evolving legislation and executive actions related to our rates enacted by individual states, such as Ohio Senate Bill 2 of 2025 and Executive Order No. 2 of 2026 issued by the New Jersey governor on January 20, 2026, may also affect outcomes in distribution rate cases or could create uncertainty around our rate strategy.
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, to determine whether FERC’s existing policies on transmission rate incentives should be revised, and to determine whether certain classes of network transmission upgrade costs can be recovered in transmission rates and whether such costs will be direct charged to the connecting customer. 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.
FERC, at the instruction of the U.S. Secretary of Energy, is also considering whether to develop regulations intended to speed interconnection of AI data centers and “hybrid” data center/electric generation facilities (collectively, “large loads”) to the transmission system. Final regulations, if any, from FERC are expected in the second quarter of 2026. To the extent the new regulations promulgated by FERC do not permit transmission utilities to fully recover costs associated with transmission network upgrades required to serve new large loads, our strategy of investing in transmission could be adversely affected.
External pressures beyond our control may increase customer rates and, when combined with state and federal regulatory action to mitigate bill impacts, may impair our ability to earn a fair and equitable return on our investments and execute our strategy.
PJM’s recent capacity auctions have been subject to a “price collar” that has resulted from all-time high generation capacity prices in recent auction outcomes. These all-time high capacity prices ultimately are passed through in retail rates and can result in material increases in retail customers’ monthly electric utility bills. On January 16, 2026, the PJM board along with various federal and state officials, expressed interest in extending the price collar through mid-2030.
In addition, the parties to the Statement of Principles suggested that PJM should conduct a “backstop” auction to procure additional generation capacity, with the costs to be allocated first to “new” data centers and second to existing PJM loads. If the PJM capacity auctions continue to clear at the auction cap, and if PJM conducts a “backstop” capacity auction that clears at a high price point, customer resistance to the resulting market driven increases on the generation portion of their bills could lead to increased pressure for state and federal utility regulators to limit the needed capital investment in transmission and distribution systems required for safe, reliable and resilient service to customers, which may impair our ability to earn a fair and equitable return on our investments and execute our strategy.
Our investments in transmission and distribution infrastructure modernization, reliability improvements, environmental compliance and storm hardening may increase customer bills over time and the resulting higher electric bills, when combined with the external pressures discussed above, may place pressure on residential customers’ affordability, particularly in portions of our service territory with lower median household income or high energy burdens and/or amongst those customers who have already seen significant retail bill increases. State and federal regulators may also adopt or modify policies intended to mitigate customer bill impacts – including disallowance or delayed recovery of certain capital investments or operating expenses, mandated bill assistance programs, changes to rate design, or restrictions on rate increases. Customer concerns regarding affordability may result in increased regulatory scrutiny, constraints on the size and timing of rate increases, expanded bill
mitigation requirements, or disallowances, any of which could adversely affect our ability to recover costs or earn our authorized return on equity. In addition, sustained increases in customer bills may lead to reduced electricity usage through conservation, energy efficiency, or distributed generation, which could limit future load growth and revenues.
Regulatory agencies may also require utilities to offset portions of rising costs related to grid modernization, resilience investments, environmental compliance, or rapidly evolving market conditions if they determine that such costs would unduly affect customer affordability. Any such actions could limit or delay our ability to recover costs or investments, earn a fair and equitable return, or maintain expected cash flows and could have an adverse effect on our businesses, financial condition, results of operations and cash flows.
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, and RFC or changes in the rules of organized markets, which could have an adverse effect on our financial condition.
Our operations are subjected to audit by FERC, NERC and RFC, which may conduct routine or special audits and issue requests designed to ensure compliance with applicable rules, regulations, policies and procedures. Among other rules, regulations, policies and procedures, 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 continue to refine existing reliability standards as well as develop and adopt new reliability standards. The reliability standards address operation, planning, and security of the bulk electricity system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection, and personnel training. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditure. If we were found not to be in compliance with one or more of the mandatory reliability standards, we and/or our subsidiaries could be subject to sanctions, including substantial monetary penalties. For example, FERC has the authority under the FPA to impose penalties up to and including $1.5 million per day, subject thereafter to annual adjustments for inflation, for failure to comply with these mandatory reliability standards. Potential non-monetary sanctions include imposing limitations on the violator’s activities or operations.
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 unreimburseddefaults 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 16,985 MWs through 2035, has the potential to adversely impact our business, results of operations, financial condition, or cash flows. At the same time, our planning could be adversely affected if electricity usage by data centers is ultimately lower than projected, which could reduce anticipated load growth.
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, severedamage to and destruction of PP&E, 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.
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, 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.
We rely on complex information technology systems to operate our generation, transmission and distribution networks and to store sensitive business, employee and customer data. Increasingly sophisticated cyber-attacks, ransomware, and other security breaches—whether targeting us or third parties with whom we do business—could disrupt operations, compromise confidential information, and result in significant financial, legal, and reputational harm. Cybersecurity threats, including those that exploitadvances in technologies such as artificial intelligence, continue to grow in frequency and sophistication, and the security controls we implement may not fully prevent or detect all such threats or incidents. Emerging artificial intelligence technologies may be used to develop new hacking tools, obscure malicious activities, exploitvulnerabilities, and increase the difficulty of detecting threats. Despite ongoing investments in cybersecurity, we cannot guarantee prevention or timely detection of all threats, which continue to evolve and may be amplified by interconnected systems. A successful attack or breach could lead to service interruptions, regulatory penalties, litigation, remediation costs, and loss of customer trust. 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 cybersecurity 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 claimsagainst 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 2026 and beyond. Inflation and broader economic conditions have continued to drive up the price of the cost of essential components used in the construction of transmission infrastructure, such as electrical equipment, steel and aluminum, and we may experience supply chain disruptions and long lead times for critical equipment. 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 greaterlosses 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.
Supply chain disruptions could have an adverse effect on our results of operations, cash flow and financial condition.
We have in the past and may in the future 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. 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. Our operations and corporate strategy may also be adversely affected by supply chain disruptions and inflation, including shortages and delays in key materials, equipment and contractor services. 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 took 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. The supply chain of goods and services we rely on could be impacted by sanctions, tariffs, manufacturing labor shortages and domestic and international shipping constraints, which could increase our costs and delay delivery of critical materials.
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 the 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.
Additionally, the operations of the Electric Companies are affected by the economic conditions in their respective service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable, which could adversely impact our financial condition, results of operations and cash flows.
FirstEnergy is subject to risks arising from the operation of its electric generation facilities 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 transmission and distribution facilities, and in the case of MP, electric generation 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.
FirstEnergy’s Energize365 business plan calls for extensive capital investments totaling approximately $36 billion from 2026 through 2030. 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 electric generation facilities, 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 seriousinjury or loss of life that may harm our business reputation and adversely affect our operating results.
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 seriousinjury 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 14., “Commitments, Guaranties and Contingencies,” of the Combined Notes to Financial Statements of the Registrants.
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. 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 Item 7., "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 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 affordability and reliability of our 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.
FirstEnergy published statements concerning its climate-related goals and aspirations. FirstEnergy is targeting Scope 1 carbon neutrality by 2050, which includes emissions, sulfur hexafluoride leaks from transmission and distribution equipment, and its mobile fleet (i.e., vehicles). These statements reflect FirstEnergy’s aspirations and are not guarantees that FirstEnergy will be able to achieve them. FirstEnergy’s failure to adequately update, accomplish or accurately track and report on these goals on a timely basis, or at all, could adversely affect its and its subsidiaries’ 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.
FirstEnergy’s ability to achieve its GHG reduction objective is subject to its ability to make operational changes and is conditioned upon numerous risks, many of which are outside of its control. Examples of such risks include the evolving regulatory requirements in the jurisdictions in which it and its subsidiaries operate, including the interpretation of such regulations, potential changes to such laws and regulations, 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 FirstEnergy is seeking to reduce costs.
Standards for tracking and reporting of climate and other environmental matters continue to evolve. FirstEnergy’s 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. FirstEnergy’s processes and controls for reporting these matters across its 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 FirstEnergy’s current goals, reported progress in achieving such goals, or ability to achieve such goals in the future. If FirstEnergy’s practices do not meet evolving investor or other stakeholder expectations and standards, then the reputations of FirstEnergy and its subsidiaries, including ours, or their attractiveness as an investment, or status as a business partner, acquiror, service provider or employer could be negatively impacted.
MP has coal-fired generation capacity, which exposes it to risk from regulations relating to coal, GHGs and CCRs, which could lead to increased costs or the need to spend significant resources to defendallegations of violation. (Applies to FE)
MP owns and maintains coal-fired electric generation facilities 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, FE's 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 MP’s 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 defendagainstallegations 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 14., "Commitments, Guarantees and Contingencies,” of the Combined Notes to Financial Statements of the Registrants. 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, but not limited to, operating and deactivated 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 CO 2 emissions and have created financial incentives to reduce them. In 2024, FirstEnergy operated businesses that had total Scope 1 GHG emissions of approximately 14 million metric tons. For existing electric generation facilities, CO 2 emissions data are either obtained directly from facility continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO 2 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 facility efficiency, fuel type, CO 2 emissions rates and our subsidiaries’ achieving completion of such construction and development projects. While actual emissions may vary substantially, the projects under construction or development when completed will increase emissions of our portfolio and therefore could increase the risks associated with regulation of GHG emissions.
In 2010, the EPA adopted regulations pertaining to GHG emissions that require new and existing sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or modification. In 2016, the Supreme Court of the U.S. ruled that such permitting would only be required if such sources also must obtain a new source review permit for increases in other regulated pollutants. For further discussion of the regulation of GHG emissions, see Note 14., "Commitments, Guarantees and Contingencies" of the Combined Notes to Financial Statements of the Registrants for additional information and discussion.
Furthermore, certain states have begun to pass their own laws related to GHG emissions and disclosure of such 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.
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 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 allegedviolation of environmental laws and regulations may require us to expend significant resources to defendagainst any such allegedviolations. 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 FirstEnergy’s electric generation facilities, which could result in the imposition of fines.
FirstEnergy 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 FirstEnergy’s electric generation facilities in a manner that results in increased emissions could subject FirstEnergy’s existing electric generation facilities to the far more stringent new source standards applicable to new electric generation facilities.
The EPA has historically 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 investigatedallegedviolations of the NSR standards at certain of our existing and former electric generation facilities. Regulatory requirements and enforcement priorities continue to change, but should the EPA investigate FirstEnergy’s electric generation facilities 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 CO 2 emissions from electric generation facilities constitute a public nuisance under federal and/or state common law. While the Registrants are not a party to this litigation, either Registrant, 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, including the NJBPU and the New Jersey General Assembly, have introduced requirements and/or incentives, as well as penalties, to reduce peak demand and energy consumption. Such conservation programs have previously resulted in and could result in further load reduction and could 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 and, in particular, whether we would be permitted to recover some or all of the resulting additional costs and/or lost revenues. Should we be required to invest in, or fund, 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 could also be adversely impacted if any future increases to energy prices result in a decrease in customer usage. Our financial results could be adversely affected if we are unable to meet participation and/or energy reduction targets, as they may be established and penalties are
imposed. 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 may have an adverse impact on FE's business operations, financial condition and cash flows.
As further described in Item 2., "Properties", FirstEnergy controls approximately 3,160 MWs of coal-fired generation, primarily at MP. Certain lenders and members of the investment community have adopted policies limiting new investments in coal-fired generation. Such efforts may adversely impact FirstEnergy's 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 FirstEnergy's 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 greatervolatility 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 Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Pension and OPEB Accounting.”
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.
FirstEnergy’s 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, 2025, FE was in compliance with its applicable
consolidated interest coverage ratio and the Electric Companies, the Transmission Companies, and FET were each 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 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 allegedfailures 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 allegedfailures 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 FE’s subsidiaries have in the past been subject to downgrade of credit ratings. Any future downgrades in FirstEnergy or its 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 bank and capital markets to meet both 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 collateral 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 obtain cash may be adversely affected. Our access to funds under those credit facilities is dependent on our 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 an adverse effect on our results of operations and financial condition.
Should there be fluctuations in the bank and capital 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, 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 bank and capital 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.
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.
We are 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 FE or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.
Specifically, the IRA of 2022 imposes a corporate AMT and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. The IRS has issued guidance, most recently on September 30, 2025, and the U.S. Treasury has issued proposed regulations concerning the corporate AMT. While FirstEnergy continues to believe, more likely than not, it will be subject to corporate AMT, additional IRS guidance or revised U.S. Treasury regulations, which are expected to be issued in the future, as well as potential tax legislation or presidential executive orders, could provide certain adjustments to regulated utilities in calculating corporate AMT, which may reduce or otherwise significantly change FirstEnergy’s AMT estimates or its conclusions as to whether it is an AMT payer. 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.
FE is a holding company and relies on cash from its subsidiaries to meet its financial obligations and therefore any restrictions on the Electric Companies and Transmission Companies’ ability to pay dividends or make cash payments to FE may adversely affect its cash flows and financial condition. (Applies to FE)
Because FE is a holding company with no operations or cash flows of its own, its ability to meet its financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on its 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 paying such dividends, FE’s 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 FE. Any inability of its subsidiaries to pay dividends or make cash payments to FE may adversely affect its cash flows and financial condition.
FE may also provide capital contributions or debt financing to its 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 FE's common stock.
FE cannot assure its common shareholders that future dividend payments will be made, or if made, in what amounts they may be paid. (Applies to FE)
The FE Board will continue to regularly evaluate FE’s 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, FE’s earnings, cash flows, credit metrics, as well as general economic and business conditions. FE 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.
JCP&L may recognize impairments of recorded goodwill, which would result in write-offs of the impaired amounts and could have an adverse effect on its results of operations. (Applies to JCP&L)
JCP&L had approximately $1.8 billion of goodwill on our balance sheet as of December 31, 2025. Goodwill is tested for impairment annually, as of July 31, or whenever events or circumstances indicate impairment may have occurred. JCP&L is unable to predict the actual timing and amounts of any impairments in future years, which would depend on many factors, including interest rates, sector market performance, JCP&L’s capital structure, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors. The recognition of impairments of goodwill, which may result in write-offs of such impaired amount, could have an adverse effect on JCP&L’s results of operations.
investigations
failure
• The risks and uncertainties associated with litigation, including the securities class-action lawsuit, regulatory proceedings, arbitration, mediation and similar proceedings;
• Changes in national and regional economic conditions, including recession, volatile interest rates, inflationary pressure, supply chain disruptions, higher fuel costs, and workforce impacts, affecting us and/or our customers and the vendors with which we do business;
• Variations in weather, such as mild seasonal weather variations and severe weather conditions (including events caused, or exacerbated, by climate change, such as wildfires, hurricanes, flooding, droughts, high wind events and extreme heat events) and other natural disasters, which may result in increased storm restoration expenses or material liability and negatively affect future operating results;
• The potential liabilities and increased costs arising from regulatory actions or outcomes in response to severe weather conditions and other natural disasters;
• Legislative and regulatory developments, and executive orders, including, but not limited to, matters related to rates, generation resource adequacy, co-location of generation and large loads, and compliance and enforcement activity;
• The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions, and the loss of FE’s status as a well-known seasoned issuer;
• The risks associated with physical attacks, such as acts of war, terrorism, sabotage or other acts of violence, and cyber-attacks and other disruptions to our, or our vendors’, information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information;
• The ability to accomplish or realize anticipated benefits through establishing a culture of continuous improvement and our other strategic and financial goals, including, but not limited to, executing Energize365, our transmission and distribution investment plan, executing on our rate filing strategy, controlling costs, improving credit metrics, maintaining investment grade ratings, strengthening our balance sheet and growing earnings;
• Changing market conditions affecting the measurement of certain liabilities and the value of assets held in FirstEnergy's pension trusts may negatively impact our forecasted growth rate, results of operations and may also cause it to make contributions to its pension sooner or in amounts that are larger than currently anticipated;
• Changes in assumptions regarding factors such as economic conditions within our territories, the reliability of our transmission and distribution system, our generation resource planning in West Virginia, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities;
• Human capital management challenges, including among other things, attracting and retaining appropriately trained and qualified employees, and labor disruptions by our unionized workforce;
• Changes to environmental laws and regulations, including, but not limited to, federal and state rules related to climate change, CCRs, and potential changes to such laws and regulations;
• Changes in customers’ demand for power, including, but not limited to, economic conditions, the impact of climate change, and emerging technology, particularly with respect to electrification, energy storage, co-location of generation and large loads, and distributed sources of generation;
• Future actions taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity;
• The potential of non-compliance with debt covenants in our credit facilities;
• The ability to comply with applicable reliability standards and energy efficiency and peak demand reduction mandates;
• Changes to significant accounting policies;
• Any changes in tax laws or regulations, including, but not limited to, the IRA of 2022, the OBBBA, or adverse tax audit results or rulings and potential changes to such laws and regulations;
• The ability to meet our publicly-disclosed goals relating to climate-related matters, opportunities, improvements, and efficiencies, including FirstEnergy’s GHG reduction goals; and
• The risks and other factors discussed from time to time in our SEC filings.
Dividends declared from time to time on FE’s common stock during any period may in the aggregate vary from prior periods due to circumstances considered by the FE Board at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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 the Registrants’ 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 FirstEnergy’s Climate Strategy, including FirstEnergy’s GHG emission reduction goals, are not an indication that these statements are necessarily material to investors or required to be disclosed in FE’s filings with the SEC. In addition, historical, current and forward-looking statements regarding climate matters, including GHG emissions, may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K discusses FirstEnergy's 2025 and 2024 results, and year-over-year comparisons between 2025 and 2024. Discussions of 2023 results and year-over-year comparisons between 2024 and 2023 that are not included in this Form 10-K can be found in Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of FirstEnergy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on February 27, 2025.
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 6 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. In addition, MP and AGC control 3,610 MWs of total generation capacity.
Segment Overview
FirstEnergy's Distribution segment, which consists of the Ohio Companies and FE PA, representing $11.1 billion in rate base as of December 31, 2025, 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 default service or standard service offer requirements. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.
FirstEnergy's Integrated segment includes the distribution and transmission operations of JCP&L, MP and PE, as well as MP’s regulated generation operations, representing $10.2 billion in rate base as of December 31, 2025. 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 3,610 MWs of regulated generation capacity located primarily in West Virginia and Virginia, which includes three solar generation sites, representing 30 MWs of generation capacity. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs. Additionally, on October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC proposing, among other things, the addition of 70 MWs of solar generation by 2028, and 1,200 MWs of natural gas combined cycle generation by 2031, which are expected to require an estimated capital investment of approximately $2.5 billion, as detailed in the filing. See Note 13., "Regulatory Matters," of the Combined Notes to Financial Statements of the Registrants for additional details.
FirstEnergy's Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, representing $5.4 billion in FirstEnergy-owned rate base as of December 31, 2025, 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.
FirstEnergy's 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. On July 16, 2025, FEV sold its entire 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations, at book value to WMB Marketing Ventures, LLC and Pinesdale LLC for $47.5 million. Also included in Corporate/Other for segment reporting is 67 MWs of generation capacity, representing AE Supply’s OVEC capacity entitlement. As of December 31, 2025, Corporate/Other had approximately $6.8 billion of external FE holding company debt.
Recent Developments
Investment Strategy
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.
FirstEnergy recently increased its customer-focused Energize365 investment plan for the 2026 to 2030 time period to $36 billion, approximately 25% higher than the previous 2025 to 2029 five-year plan, and aims to strengthen the grid, improve reliability and support growing customer demand. Through the Energize365 program, system-wide capital investments from 2026 to 2030 are expected to comprise the Distribution segment 28%, the Integrated segment 35%, and the Stand-Alone Transmission segment 35%, focused on the following:
• Distribution and Transmission investments to support improvements in grid reliability and resiliency and support growing customer demand, including through:
• Programs to drive system resiliency through automation technology and communication, including 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 projects to support increased data center load;
• Enhancing system performance by implementing new designs and technologies to reduce load at risk;
• Upgrading system conditions that enhance reliability; and
• Transmission projects awarded through the PJM Open Window to address regional expansion projects.
• Base distribution projects to address aging infrastructure.
• Generation maintenance projects that maintain operations of fossil electric generation facilities 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 2030, which are expected to strengthen the grid and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.
Finance
FirstEnergy aims to execute its Energize365 investment plan through a strengthened financial position. Energize365 capital investments included in the current five-year plan are expected to be funded with a combination of organic cash flows, the issuance of debt, including hybrid securities, and the issuance of common equity. FirstEnergy believes it 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.
Dividend Growth
FirstEnergy continues to return value to shareholders. In February 2026, the FE Board declared a $0.02 per share increase to the quarterly cash common stock dividend to $0.465 per share payable June 1, 2026, which represents a 4.5% increase compared to dividends declared in 2025. Modest dividend growth is expected to enableenhanced 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, cash flows, credit metrics and general economic and other business conditions.
Reorganization
On March 24, 2025, FirstEnergy internally announced organizational changes that are intended to align the organization with its new business model, which is designed to make FirstEnergy more efficient and sustainable while placing responsibility and accountability closer to customers, employees and regulators. The changes are also consistent with FirstEnergy’s focus on operations and maintenance expense discipline. As a result, FirstEnergy recognized a pre-tax charge of approximately $26 million ($5 million at JCP&L) in the first quarter of 2025, which is included within “Other operating expenses” on each of the Registrants' Statements of Income and Comprehensive Income.
Signal Peak Disposition
On July 16, 2025, FEV sold its entire 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations, at book value to WMB Marketing Ventures, LLC and Pinesdale LLC for $47.5 million, which is classified within cash flows from investing activities - other of FirstEnergy’s Consolidated Statements of Cash Flows.
Valley Link
On February 21, 2025, FET, DominionHV and Transource entered into the Valley Link Operating Agreement, which established the general framework for Valley Link and the Valley Link Subsidiaries to accept, design, develop, construct, own, operate and finance those transmission projects awarded by PJM to Valley Link. This general framework includes parameters regarding the
relationship among the three members, confers governance rights to its members so long as certain ownership percentages are maintained, as described below, and defines the list of projects that Valley Link will have the right to develop. Valley Link is the owner of the Valley Link Subsidiaries, which are organized in various states. On February 26, 2025, in response to the PJM 2024 RTEP Long-Term Proposal Window #1, PJM awarded two electric transmission projects to Valley Link estimated to be approximately $3 billion, with FET’s share estimated to be approximately $1 billion.
Grid Growth
On February 13, 2026, FET and Transource entered into the Grid Growth Operating Agreement, which established the general framework for FET and Transource to accept, design, develop, construct, own, operate and finance those transmission projects awarded by PJM to certain of the subsidiaries of Grid Growth, on February 12, 2026. This general framework includes parameters regarding the relationship among the two members, confers governance rights to its members so long as certain ownership percentages are maintained and defines the list of projects that Grid Growth will have the right to develop. Grid Growth is the sole owner of Grid Growth Ohio and owns an 80% interest in Grid Growth EHV, with Transource owning the remaining interests. On February 12, 2026, in response to the PJM 2025 RTEP Long-Term Proposal Window #1, PJM awarded a project to Grid Growth estimated to be approximately $1 billion, with FET’s share estimated to be approximately $448 million.
Regulatory Matters - New Jersey
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ petition with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. On April 10, 2025, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s amended EnergizeNJ petition. The settlement provides for total program costs of $339 million, including capital investments in JCP&L’s electric distribution system of approximately $203 million, $132 million of matching capital investments and approximately $4 million of O&M expense. Pursuant to the settlement, the program began on July 1, 2025, and will continue through December 31, 2028, and JCP&L has agreed to file a base rate case no later than January 1, 2030.
Regulatory Matters - Ohio
On April 5, 2023, the Ohio Companies sought approval from the PUCO for their ESP V. The proposed plan would maintain an eight-year term beginning June 1, 2024, and continue riders recovering costs associated with distribution infrastructure investments and approved grid modernization investments. ESP V additionally proposed new riders that would support reliability, and included provisions supporting affordability and enhancing the customer experience. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which are described in “Outlook - State Regulation - Ohio,” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations". 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 in “Outlook - State Regulation - Ohio,” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations". On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV. On May 22, 2025, the Supreme Court of Ohio granted the Ohio Companies motion to intervene in the appeal as appellees. On July 7, 2025, OCC and NOAC filed their Appellants’ brief. Appellees, including the Ohio Companies, filed their briefs on August 26, 2025, to which the OCC and NOAC replied on September 15, 2025.
On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI, which would have begun concurrently with the effective date of any new base distribution rates resulting from the Ohio Companies’ 2024 base rate case and continued through May 31, 2028. On May 15, 2025, the Ohio Governor signed HB 15, which repealed the statute authorizing ESPs in Ohio, eliminating the PUCO’s ability to authorize future ESPs such as ESP VI. On December 17, 2025, the PUCO dismissed ESP VI due to the repeal of the ESP statute pursuant to HB 15. HB 15 permits the Ohio Companies to continue ESP IV until their final auction delivery period on May 31, 2029, at which time ESP IV must terminate.
On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing included 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 incorporated 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. On November 19, 2025, the PUCO issued an order in the rate case lifting the rate freeze and approving a net increase in base distribution revenues of the Ohio Companies of approximately $34 million, with a return on equity of 9.63% and a hypothetical capital structure of 48.8% debt and 51.2% equity for all three Ohio Companies, which reflects a roll-in of current riders such as DCR and AMI. The PUCO authorized continuance of Rider DCR with a cap increase commensurate with capital investments through January 31, 2025, and approved the Ohio Companies’ proposal to change pension and OPEB recovery to the delayed recognition method. Additionally, the order authorizes recovery of certain deferred costs for storm restoration, operations and maintenance, and energy efficiency. As a result of the order, the Ohio Companies recognized a $352 million pre-tax impairment charge related to the disallowance from future recovery of certain previously capitalized amounts. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025 base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On January 9, 2026, the Ohio Companies filed an expedited motion for ruling on the proposed compliance tariffs and on February 4, 2026, PUCO staff issued a letter recommending that most of the Ohio Companies’ proposed compliance tariffs be approved. The Ohio Companies cannot predict the outcome of the rehearing, but do not expect material changes to the November 2025 order.
On May 15, 2025, the Ohio Governor signed HB 15 that, in addition to eliminating ESPs, requires, among other things, triennial base rate cases and allows them to be based on a three-year forecasted test period, expedites PUCO review and disposition of future base rate cases, imposes annual reliability reporting, increases protections for customers shopping with third-party suppliers, requires EDUs to develop and publicly share distribution system hosting capacity maps, and reduces certain transmission and distribution property taxes beginning with property in-serviced in 2026. The legislation became effective August 14, 2025.
On November 19, 2025, the PUCO issued a separate order which assessed approximately $250 million in monetary penalties upon the Ohio Companies in connection with the PUCO’s ongoing HB 6 audits and investigations. On December 19, 2025, the Ohio Companies and fourteen intervenors filed with the PUCO an unopposed stipulation and recommendation that was intended to resolve several matters pending before the PUCO to which the Ohio Companies were a party. The stipulation and recommendation, which was adopted in its entirety by the PUCO on January 7, 2026, vacated the amounts owed pursuant to the November 19, 2025 order regarding its HB 6 audits and investigations and instead directed the Ohio Companies to pay its customers restitution and refunds totaling approximately $275 million, among other things. The refunds will be paid out over three billing cycles beginning in February 2026.
The Ohio Companies anticipate filing a base rate distribution case with the PUCO in the second half of 2026.
Regulatory Matters - West Virginia
On October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC. To ensure that MP and PE can meet their PJM adequacy requirements, the plan proposes, among other things, near-term market capacity purchases and the addition of 70 MWs of solar generation by 2028 and 1,200 MWs of natural gas combined cycle generation by 2031. On November 26, 2025, the WVPSC issued a procedural order setting a hearing for May 2026.
On February 13, 2026, MP and PE filed a CPCN to construct and operate a 1,200 MW combined cycle gas turbine plant and 70 MWs of solar generation capacity for an estimated capital investment totaling approximately $2.7 billion as of the date of the filing. The request also includes a surcharge designed to recover financing costs during development and construction of the projects, as well as to transition to recovery in base rates once the projects are placed in-service and approved through a base rate case. An order is expected from the WVPSC in the second half of 2026.
MP and PE anticipate filing a base rate distribution case with the WVPSC in the second half of 2026.
Regulatory Matters - Maryland
PE anticipates filing a base rate distribution case with the MDPSC in the second half of 2026.
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 criminalallegations 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, criminalprosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the January 17, 2025, indictmentagainst two former FirstEnergy senior officers, as described below in “Outlook -- Other Legal Proceedings - U.S. v. Larry Householder, et al., ” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations". 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.
See “Outlook - Other Legal Proceedings” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional details regarding the DPA, and ongoing litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for details on the now-resolved PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FirstEnergy’s financial condition, results of operations and cash flows. The FirstEnergy leadership team remains committed and focused on executing its strategy and running the business.
FIRSTENERGY'S CONSOLIDATED RESULTS OF OPERATIONS
2025 Compared with 2024
(In millions)
For the Years Ended December 31,
Increase (Decrease)
Revenues
Operating expenses
Other expenses, net
Income taxes
Income attributable to noncontrolling interest
Earnings attributable to FE
Earnings attributable to FE was $1,020 million or $1.77 per basic share ($1.76 per diluted share) in 2025 compared to $978 million or $1.70 per basic and diluted share in 2024, representing an increase of $42 million that was primarily due to the following:
• The absence of the $100 million civil penalty resulting from the SEC investigation and the $19.5 million settlement with the OAG’s office in 2024;
• The absence of $200 million (pre-tax) in charges related to changes in ARO liabilities associated with new CCR rules and the McElroy’s Run impoundment facility in 2024 and a $49 million reduction in ARO liabilities in 2025 based on the completion of engineering studies and field analysis of certain sites;
• The absence of a $53 million (pre-tax) charge at JCP&L in connection with the base rate case settlement agreement in the first quarter of 2024, as further discussed below;
• The absence of a $32.5 million (pre-tax) contribution commitment by the Ohio Companies, as a result of the PUCO’s ESP V order in the second quarter of 2024;
• Higher earnings associated with the implementation of base rate cases in New Jersey, West Virginia and Pennsylvania;
• Higher customer usage and demand;
• Higher revenues from regulated capital investments that increased rate base;
The absence of the $62 million (pre-tax) impairment charge related to the Akron general office in the third quarter of 2024;
• Lower debt redemptions costs of $61 million (pre-tax); and
• Higher income tax benefits primarily related to an increase in the remeasurement of excess deferred income taxes compared to 2024, and the absence of discrete tax charges related to the FET Equity Interest Sale and PA Consolidation in the first quarter of 2024.
These factors were partially offset by the following:
• A $352 million (pre-tax) impairment charge recognized in the fourth quarter of 2025 related to disallowances in the Ohio base rate case resulting from the PUCO-approved order;
• A $275 million (pre-tax) charge recognized in the fourth quarter of 2025 resulting from the Ohio Companies' PUCO-approved settlement that will provide restitution and refunds to customers;
• The absence of $151 million (pre-tax) net proceeds from the shareholder derivative lawsuit settlement received in the second quarter of 2024;
• The absence of a $60 million (pre-tax) benefit associated with the approval by the WVPSC to recover costs of certain retired generation stations in the first quarter of 2024;
• The absence of a $46 million (pre-tax) charge in the fourth quarter of 2024 from the expected elimination of the 50 basis point ROE adder associated with ATSI’s RTO membership as a result of the Sixth Circuit ruling;
• Higher depreciation expense due to a higher asset base;
• Higher other operating expenses, primarily due to higher employee benefit costs and planned vegetation management expenses, partially offset by increased construction support and lower maintenance work;
• Lower investment earnings of $58 million (pre-tax) primarily related to FEV’s equity method investment in Global Holding, which, as discussed above, was sold on July 16, 2025;
• The absence of $24 million (pre-tax) of interest income related to the FET Equity Interest Sale, the purchase price of which was paid in part by the issuance of promissory notes;
• Costs associated with organizational changes announced in March 2025;
• The dilutive effect of the FET Equity Interest Sale that closed in March 2024; and
• Lower customer credits associated with the PUCO-approved Ohio Stipulation.
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)
Increase (Decrease)
Increase (Decrease)
Residential
Commercial (2)
Industrial
Total Electric Distribution MWh Deliveries
(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.
Actual distribution deliveries in 2025 for the residential and commercial customer classes were higher than 2024, primarily due to impacts of weather temperatures. Cooling degree days in 2025 were 12% below 2024 and flat to normal. Heating degree days in 2025 were 19% above 2024 and 3% above 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 15., “Segment Information,” of the Combined Notes to Financial Statements of the Registrants.
Summary of Segment Results of Operations — 2025 Compared with 2024
Financial results for FirstEnergy’s business segments for the years ended December 31, 2025 and 2024, were as follows:
2025 Financial Results
(In millions)
Distribution
Integrated
Stand-Alone Transmission
Corporate/Other and Reconciling Adjustments
FirstEnergy Consolidated
Revenues:
Electric
Other
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Provision for depreciation
Amortization (deferral) of regulatory assets, net
General taxes
Ohio settlement charges
Impairment of assets
Total Operating Expenses
Other Income (Expense):
Debt redemption costs
Miscellaneous income (expense), net
Pension and OPEB mark-to-market adjustments
Interest expense
Capitalized financing costs
Total Other Expense
Income taxes (benefits)
Income attributable to noncontrolling interest
Earnings (Losses) Attributable to FE
2024 Financial Results
(In millions)
Distribution
Integrated
Stand-Alone Transmission
Corporate/Other and Reconciling Adjustments
FirstEnergy Consolidated
Revenues:
Electric
Other
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Provision for depreciation
Amortization (deferral) of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Other Income (Expense):
Debt redemption costs
Equity method investment earnings, net
Miscellaneous income (expense), net
Pension and OPEB mark-to-market adjustments
Interest expense
Capitalized financing costs
Total Other Expense
Income taxes (benefits)
Income attributable to noncontrolling interest
Earnings (Losses) Attributable to FE
Changes Between 2025 and 2024
Financial Results
Increase (Decrease)
Distribution
Integrated
Stand-Alone Transmission
Corporate/Other and Reconciling Adjustments
FirstEnergy Consolidated
(In millions)
Revenues:
Electric
Other
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Provision for depreciation
Amortization (deferral) of regulatory assets, net
General taxes
Ohio settlement charges
Impairment of assets
Total Operating Expenses
Other Income (Expense):
Debt redemption costs
Equity method investment earnings, net
Miscellaneous income (expense), net
Pension and OPEB mark-to-market adjustments
Interest expense
Capitalized financing costs
Total Other Expense
Income taxes (benefits)
Income attributable to noncontrolling interest
Earnings (Losses) Attributable to FE
Distribution Segment — 2025 Compared with 2024
Distribution segment's earnings attributable to FE decreased $261 million in 2025, as compared to 2024, primarily due to charges recognized in the fourth quarter of 2025 resulting from the Ohio Companies' PUCO-approved settlement that will provide $275 million in restitution and refunds to customers, and $352 million in impairment charges resulting from the PUCO-approved base rate case order, partially offset by higher revenues associated with the implementation of the Pennsylvania base rate case, higher customer usage and demand, and higher Pension and OPEB mark-to-market adjustments.
Revenues —
Distribution's total revenues increased $684 million as a result of the following sources:
For the Years Ended December 31,
Revenues by Type of Service
Increase
(In millions)
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Other
Total Revenues
Distribution services revenues increased $447 million in 2025, as compared to 2024, primarily resulting from higher customer usage due to colder weather temperatures in the first and fourth quarters, lower customer credits associated with the PUCO-approved Ohio Stipulation, and higher revenues associated with the implementation of the Pennsylvania base rate case, partially offset by milder weather temperatures in the second quarter that lowered customer usage and demand. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.
Generation sales revenues increased $237 million in 2025, as compared to 2024, primarily due to higher non-shopping generation auction rates, higher retail generation sales volumes as a result of colder weather temperatures in the first and fourth quarters, and lower shopping, which increased sales volumes. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA decreased to 89% from 90% in Ohio and to 62% from 63% in Pennsylvania, as compared to 2024. Retail and wholesale generation sales revenue have no material impact to earnings.
Operating Expenses —
Total operating expenses increased $1,109 million, primarily due to the following:
• Purchased power costs, which have no material impact to earnings, increased $239 million in 2025, as compared to 2024, primarily due to higher generation sales volumes and unit costs, as described above.
• Other operating expenses increased $101 million in 2025, as compared to 2024, primarily due to:
• Higher network transmission expenses of $69 million, which are deferred for future recovery, resulting in no material impact to earnings;
• Higher planned and accelerated vegetation management expenses of $54 million, primarily in Pennsylvania as approved and recovering in the base rate case;
• Higher uncollectible expenses of $22 million, of which $15 million were deferred for future recovery;
• Higher energy efficiency and other state mandated program costs of $65 million, which were deferred for future recovery, resulting in no material impact to earnings; and
• Higher other operating expense of $57 million, primarily due to severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025, higher employee benefit costs, and higher material and contractor expenses, partially offset by increased construction support and lower maintenance work.
This increase was partially offset by:
• The absence of a $32.5 million contribution commitment by the Ohio Companies, as a result of the PUCO’s ESP V order in the second quarter of 2024;
• The absence of a $46 million charge during the second quarter of 2024 related to changes in ARO liabilities associated with new CCR rules; and
• Lower storm restoration expenses of $88 million in 2025 as compared to 2024, which were mostly deferred for future recovery.
• Depreciation expense increased $7 million in 2025, as compared to 2024, primarily due to a higher asset base.
• Deferral of regulatory assets decreased $68 million in 2025, as compared to 2024, primarily due to a $79 million net decrease from lower deferred storm restoration expenses, a $21 million net decrease in generation and transmission related deferrals and a $10 million net decrease in other deferrals, partially offset by $42 million of higher net amortization expenses resulting from recovery of previously deferred storm costs and customer assistance programs from the implementation of the Pennsylvania base rate case in 2025.
• General taxes increased $97 million in 2025, as compared to 2024, primarily due to higher gross receipts and Ohio personal property taxes.
• Impairment of assets increased $322 million in 2025, as compared to 2024, due to a $352 million impairment charge related to disallowances in the Ohio base rate case resulting from the PUCO-approved order, partially offset by the absence of a $30 million impairment charge related to the Akron general office in the third quarter of 2024.
Other Expense —
Other expense decreased $103 million in 2025, as compared to 2024, primarily due to higher pension and OPEB mark-to-market adjustments and higher capitalized interest, partially offset by lower interest income on regulated money pool investments. Additionally, interest expense decreased primarily as a result of debt redemptions since 2024, partially offset by new debt issued in 2025.
Income Taxes —
Distribution segment's effective tax rate was 16.9% and 17.8% for 2025 and 2024, respectively. The decrease in the effective tax rate was primarily due to an increase in the benefit from state related flow-through items, partially offset by the absence of a discrete tax benefit from a remeasurement of excess deferred income taxes recognized in 2024.
Integrated Segment — 2025 Compared with 2024
Integrated segment’s earnings attributable to FE increased $53 million in 2025, as compared to 2024, primarily due to the implementation of base rate cases in New Jersey and West Virginia in 2025, higher customer usage and demand, higher revenues from regulated investment programs, and the absence of a $53 million charge at JCP&L in connection with the base rate case settlement agreement in the first quarter of 2024, as further discussed below, partially offset by costs associated with the announced organizational changes and the absence of a benefit associated with the approval by the WVPSC to recover costs of certain retired generation stations in the first quarter of 2024.
Revenues —
Integrated segment’s total revenues increased $807 million as a result of the following sources:
For the Years Ended December 31,
Revenues by Type of Service
Increase
(In millions)
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Transmission revenues:
JCP&L
Total transmission revenues
Other
Total Revenues
Distribution services revenues increased $98 million in 2025, as compared to 2024, primarily resulting from higher customer usage as a result of colder weather temperatures in the first and fourth quarters, higher revenues from the implementation of base rate cases, and higher rider revenues associated with certain regulated investment programs, partially offset by lower customer usage as a result of the milder weather temperatures in the second and third quarters of 2025. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.
Generation sales revenues increased $662 million in 2025, as compared to 2024, primarily due to higher retail and wholesale revenues.
• Retail generation sales increased $431 million in 2025, as compared to 2024, primarily due to higher non-shopping generation auction rates and higher volumes as a result of colder weather temperatures in the first and fourth quarters. Retail generation sales, other than those in West Virginia, have no material impact to earnings.
• Wholesale generation revenues increased $231 million in 2025, as compared to 2024, primarily due to higher sales volumes, wholesale rates and capacity revenues. 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 $45 million in 2025, as compared to 2024, primarily due to higher rate base from regulated investment programs and higher recovery of transmission operating expenses.
Operating Expenses —
Total operating expenses increased $813 million in 2025, as compared to 2024, primarily due to:
• Fuel costs increased $188 million in 2025, as compared to 2024, primarily due to higher unit costs and higher consumption volumes. Due to the ENEC, fuel expense has no material impact to earnings.
• Purchased power costs, which have no material impact to earnings, increased $435 million in 2025, as compared to 2024, primarily due to higher unit costs and capacity expenses.
• Other operating expenses increased $162 million in 2025, as compared to 2024, primarily due to:
• Higher network transmission expenses of $50 million, which were deferred for future recovery, resulting in no material impact to earnings;
• Higher uncollectible expenses of $5 million, which were deferred for future recovery;
• Higher other operating expenses of $41 million, primarily due to severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025, higher employee benefit costs and higher material and contractor spend, partially offset by increased construction support and lower maintenance work;
• Higher energy efficiency and other state mandated program costs of $72 million, which were deferred for future recovery, resulting in no material impact to earnings;
• Higher formula rate transmission operating and maintenance expenses of $5 million, which have no material impact to earnings; and
• Higher storm restoration expenses of $22 million, which were mostly deferred for future recovery.
This increase was partially offset by:
• The absence of a $33 million change in ARO liabilities associated with new CCR rules in 2024 and a reduction in 2025 based on the completion of engineering studies and field analysis of certain sites.
• Depreciation expense increased $41 million in 2025, as compared to 2024, primarily due to a higher asset base.
• Deferral of regulatory assets decreased $54 million in 2025, as compared to 2024, primarily due to the absence of the approval in the first quarter of 2024 to recover $60 million in costs of certain retired generation stations approved by the WVPSC, a $24 million adjustment associated with smart meter cost of removal expenses associated with the deployment of the AMI program in New Jersey, a $24 million decrease due to the absence of the amortization of a regulatory liability related to customer refunds in 2024 and a $1 million net decrease in other deferrals, partially offset by a $33 million net increase from higher generation and transmission related deferrals, and $22 million in higher deferral of storm related expenses including the absence of the approval in the first quarter of 2024 to recover $11 million in previously incurred storm costs.
• Impairment of assets decreased $70 million in 2025, as compared to 2024, due to:
• The absence of a $53 million pre-tax 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; and
• The absence of a $17 million impairment charge related to the Akron general office in the third quarter of 2024.
Other Expense —
Other expense decreased $96 million in 2025, as compared to 2024, primarily due the absence of certain nonrecoverable charges recognized in 2024, higher capitalized interest and higher Pension and OPEB mark-to-market adjustments. Additionally, interest expense decreased, primarily due to lower average short-term borrowings and debt redemptions in the fourth quarter of 2025, partially offset by new debt issuances since 2024.
Income Taxes —
Integrated segment’s effective tax rate was 24.4% and 22.2% in 2025 and 2024, respectively. The increase in the effective tax rate was primarily due to the absence of a discrete tax benefit related to a remeasurement of excess deferred income taxes recognized in the third quarter of 2024, partially offset by the absence of a tax charge recognized in the first quarter of 2024 related to the remeasurement of a valuation allowance for the expected utilization of certain NOL carryforwards.
Stand-Alone Transmission Segment — 2025 Compared with 2024
Stand-Alone Transmission’s earnings attributable to FE increased $63 million in 2025, as compared to 2024, primarily due to a discrete tax benefit related to a remeasurement of excess deferred income taxes in the third quarter of 2025, the absence of a charge for an expected refund, with interest, in the fourth quarter of 2024 as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership , the absence of a discrete tax charge related to the FET Equity Interest Sale in the first quarter of 2024, and higher revenues from regulated capital investments that increased rate base, partially offset by the dilutive effect of the FET Equity Interest Sale that closed in March 2024 and true-up adjustments from the annual forward looking transmission rate filings.
Revenues —
Total revenues increased $118 million in 2025, as compared to 2024, primarily due to a higher rate bas e, the absence of a charge for an expected refund, with interest, in the fourth quarter of 2024 as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership, and higher recovery of transmission operating expenses, partially offset by true-up adjustments from the annual forward looking transmission rate filings.
For the Years Ended December 31,
Revenues by Transmission Asset Owner
Increase (Decrease)
(In millions)
ATSI
TrAIL
MAIT
KATCo
Other
Total Revenues
Operating Expenses —
Total operating expenses increased $26 million in 2025, as compared to 2024, primarily due to higher depreciation and property tax expenses from a higher asset base, partially offset by lower operating and maintenance expenses and the absence of a $12 million impairment charge associated with the Akron general office in the third quarter of 2024. Other than the impairment charge, nearly all operating expenses are recovered through formula rates.
Other Expense —
Total other expense increased $1 million in 2025, as compared to 2024, primarily due to higher interest expenses from new long-term debt issuances, partially offset by higher capitalized financing costs, higher pension and OPEB mark-to-market adjustment, and the absence of a prior year non-recoverable charge.
Income Taxes —
Stand-Alone Transmission's effective tax rate was 14.0% and 28.1% for 2025 and 2024, respectively. The decrease in the effective tax rate was primarily due to a discrete tax benefit related to a remeasurement of excess deferred income taxes recognized in the third quarter of 2025, and the absence of a tax charge related to the FET Equity Interest Sale in the first quarter of 2024.
Corporate/Other — 2025 Compared with 2024
Financial results from Corporate/Other resulted in a $187 million decrease in losses attributable to FE for 2025 compared to 2024, primarily due to:
• The absence of the $100 million civil penalty resulting from the SEC investigation and the $19.5 million settlement with the OAG's office in 2024;
• $134 million (after-tax) due to the absence of a charge related to changes in ARO liabilities associated with the new CCR rules and the McElroy's Run CCR impoundment facility in 2024, and a reduction in ARO liabilities in 2025 based on the completion of engineering studies and field analysis of certain sites;
• $82 million (after-tax) due to the change in the pension and OPEB mark-to-market adjustment; and
$47 million (after-tax) of lower debt redemption costs.
The decrease in losses were partially offset by:
• The absence of $116 million (after-tax) of net proceeds from the shareholder derivative lawsuit settlement received in 2024;
• $48 million (after-tax) in lower investment earnings related to FEV’s equity method investment in Global Holding, which as discussed above, was sold on July 16, 2025;
• $27 million (after-tax) in lower pension/OPEB non-service credits primarily due to lower expected returns on plan asset credits, partially offset by lower interest costs;
• The absence of $19 million (after-tax) of interest income related to the FET Equity Interest Sale, the purchase price of whic h was paid in part by the issuance of promissory notes; and
• Lower discrete income tax benefits in 2025, partially offset by the absence of a discrete tax charge related to the PA Consolidation in the first quarter of 2024.
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. The Registrants 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.
FirstEnergy has regulatory assets of $829 million and $617 million, and regulatory liabilities of $1,185 million and $995 million as of December 31, 2025 and 2024, respectively. The following table provides information about the composition of FirstEnergy's net regulatory assets and liabilities as of December 31, 2025 and 2024, and the changes during the year 2025:
As of December 31,
Net Regulatory Assets (Liabilities) by Source - FirstEnergy
Change
(In millions)
Customer payables for future income taxes
Spent nuclear fuel disposal costs
Asset removal costs
Deferred transmission costs
Deferred generation costs
Deferred distribution costs
Storm-related costs
Energy efficiency program costs
New Jersey societal benefit costs
Vegetation management costs
Ohio settlement charges
Other
Net Regulatory Liabilities included on FirstEnergy Consolidated Balance Sheets
The following table provides information about the composition of JCP&L's net regulatory assets and liabilities as of December 31, 2025 and 2024, and the changes during the year 2025:
As of December 31,
Net Regulatory Assets (Liabilities) by Source - JCP&L
Change
(In millions)
Customer payables for future income taxes
Spent nuclear fuel disposal costs
Asset removal costs (1)
Deferred transmission costs
Deferred distribution costs
Storm-related costs
Energy efficiency program costs
New Jersey societal benefit costs
Other
Net Regulatory Assets included on JCP&L's Balance Sheets
(1) Previously issued 2024 JCP&L amounts have been revised due to the correction of immaterial errors as discussed in Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants.
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 PP&E for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to federal and state tax rate changes such as the TCJA 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 generation facilities, Oyster Creek and Three Mile Island Unit 1.
Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement.
Deferred transmission costs - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.
Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034), the Warrior Run purchase power agreement termination fee at PE (amortized through 2029), and 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 New Jersey temporary residential bill credits (amortized through February 2026), the Ohio Companies' deferral of certain distribution-related expenses, including interest (amortized through 2034) and JCP&L's AMI program costs.
Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $335 million and $73 million for FE and JCP&L, respectively, are currently being recovered through rates as of December 31, 2025. Approximately $402 million and $41 million for FE and JCP&L, respectively, are currently being recovered through rates as of December 31, 2024.
Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including New Jersey energy efficiency and renewable energy programs, FE PA's Energy Efficiency and Conservation programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland Surcharge. Investments in certain of these energy efficiency programs earn a long-term return.
New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and the New Jersey Clean Energy program.
Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey, certain distribution and transmission vegetation management costs in West Virginia, and certain transmission vegetation management costs at ATSI (amortized through 2030) and KATCo (amortized through 2036).
Ohio settlement charges - Reflects refunds and restitution owed to customers associated with the Ohio Companies' PUCO-approved settlement order. See Note 13., "Regulatory Matters," of the Combined Notes to Financial Statements of the Registrants for additional details.
The following table provides information about the composition of FirstEnergy's net regulatory assets that do not earn a current return as of December 31, 2025 and 2024, of which approximately $802 million and $698 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:
Regulatory Assets by Source Not Earning a
As of December 31,
Current Return - FirstEnergy
Change
(In millions)
Deferred generation costs
Deferred distribution costs
Storm-related costs
Other
FirstEnergy's Regulatory Assets Not Earning a Current Return
The following table provides information about the composition of JCP&L's net regulatory assets that do not earn a current return as of December 31, 2025 and 2024, of which approximately $76 million and $45 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral:
Regulatory Assets by Source Not Earning a
As of December 31,
Current Return - JCP&L
Change
(In millions)
Deferred distribution costs
Storm-related costs
Other
JCP&L's Regulatory Assets Not Earning a Current Return
CAPITAL RESOURCES AND LIQUIDITY
The Registrants' businesses are capital intensive, requiring significant resources to fund operating expenses, construction and other investment expenditures, scheduled debt maturities and interest payments, dividend payments and potential contributions to its pension plan.
The Registrants expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2026 and beyond, the Registrants expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by the Registrants, which may include hybrid securities by FE, 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. Additionally, FE may issue its common equity to fund capital expenditures in its 2026 through 2030 planning period averaging approximately 1% of its now current market capitalization in each year of the planning period, subject to market conditions and other factors.
Capital investments by business segment for FirstEnergy are included below:
FirstEnergy Business Segment
2023 Actual
2024 Actual
Actual
Distribution
Integrated (1)
Stand-Alone Transmission
Corporate/Other
Total - FirstEnergy
(1) Includes capital expenditures and capital-like investments that earn a return.
Capital investments by business segment for JCP&L are included below:
JCP&L Business Segment
2023 Actual
2024 Actual
Actual
Distribution (1)
Transmission
Total - JCP&L
(1) Includes capital expenditures and capital-like investments that earn a return.
Capital investment forecasts for the years ended 2026, 2027, 2028, 2029, and 2030 for the FirstEnergy business segments are included below:
FirstEnergy Business Segment
Forecast
2027 Forecast
2028 Forecast
2029 Forecast
2030 Forecast
Distribution
Integrated (1)
Stand-Alone Transmission (2)
Corporate/Other
Total - FirstEnergy
(1) Includes capital expenditures and capital-like investments that earn a return.
(2) Including Brookfield's noncontrolling interest in FET and FET's share of joint ventures.
Capital investment forecasts for the years ended 2026, 2027, 2028, 2029, and 2030 for the JCP&L business segments are included below:
JCP&L Business Segment
Forecast
2027 Forecast
2028 Forecast
2029 Forecast
2030 Forecast
Distribution (1)
Transmission
Total - JCP&L
(1) Includes capital expenditures and capital-like investments that earn a return.
In alignment with FirstEnergy’s strategy to invest in its segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated subsidiaries to issue and/or refinance debt.
Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.
While supply lead times have not fully returned to levels prior to the COVID-19 pandemic, FirstEnergy continues to monitor the situation in light of demand increases across the industry, including due to data center usage, and the imposition of tariffs and retaliatory tariffs that have been, and may be, imposed by the U.S. government in response. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, the situation remains fluid, and a prolonged continuation or further increase in demand, or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
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. FirstEnergy will continue to evaluate other lift-outs in the future based on market and other conditions.
As of December 31, 2025, 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.
As of December 31, 2025, JCP&L’s net deficit in working capital (current assets less current liabilities) was primarily due to accounts payable, short-term borrowings, accrued interest, and compensation and benefits. JCP&L believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below.
On October 27, 2025, FE, the Electric Companies, Transmission Companies and FET, each entered into an amended credit facility to, among other things: (i) remove the 10 basis point credit spread adjustment from the interest rate calculation; (ii) permit a one-week interest period for any Term Benchmark Advance (as defined under each of the Amended Credit Facilities) based upon daily simple SOFR; and (iii) extend the maturity date of each credit facility for an additional one-year period (a) from October 20, 2028 to October 20, 2029 for the KATCo credit facility, (b) from October 20, 2029 to October 20, 2030 for the FET credit facility and (c) from October 18, 2028 to October 18, 2029 for the remaining Amended Credit Facilities.
Borrowings under each of the Amended 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 Amended 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 Amended Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its credit facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters.
Each of the Amended 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 $325 million and $550 million of outstanding short-term borrowings as of December 31, 2025 and 2024, respectively. FirstEnergy’s available liquidity from external sources as of February 16, 2026, was as follows:
Revolving Credit Facilities
Maturity
Commitment
Available Liquidity
(In millions)
October 2029
FET
October 2030
Ohio Companies
October 2029
October 2029
JCP&L
October 2029
MP and PE
October 2029
ATSI, MAIT and TrAIL
October 2029
KATCo
October 2029
Subtotal
Cash and Cash equivalents
Total
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, 2025:
Individual Borrower
Regulatory Debt Limitations
Credit Facility Commitment
Debt-to-Total-Capitalization Ratio
(In millions)
ATSI (1)
CEI (1)
FET
JCP&L (1)
KATCo (1)
MAIT (1)
TrAIL (1)
(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 amended 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, 2025 was approximately 4.4 times.
Subject to each borrower’s sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the Amended 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 Amended Credit Facilities and against the applicable borrower’s borrowing sublimit. As of December 31, 2025, FirstEnergy had $185 million in outstanding LOCs, $52 million of which are issued under the Amended Credit Facilities.
Revolving Credit Facilities
LOC Availability as of December 31, 2025
LOC Utilized as of December 31, 2025
(In millions)
FET
Ohio Companies
JCP&L
MP and PE
ATSI, MAIT and TrAIL
KATCo
Each of the Amended 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 Amended Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the credit facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of December 31, 2025, FE was in compliance with its applicable consolidated interest coverage ratio and the Electric Companies, the Transmission Companies, and FET were each in compliance with their debt-to-total-capitalization ratio covenants under each of their Amended Credit Facilities.
FirstEnergy Money Pools
FirstEnergy’s regulated operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. 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 participates 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
For the Years Ended December 31,
Long-Term Debt Capacity
FE 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 and its subsidiaries’ credit ratings as of February 17, 2026:
Corporate Credit Rating
Senior Secured
Senior Unsecured
Outlook/Credit/Watch (1)
Issuer
Moody’s
Fitch
Moody’s
Fitch
Moody’s
Fitch
Moody’s
Fitch
BBB+
Baa3
BBB
BBB
Baa3
BBB
Distribution:
CEI
BBB+
Baa3
BBB+
BBB+
Baa3
BBB+
BBB+
Baa2
BBB+
Integrated:
JCP&L
BBB+
BBB+
BBB
Baa2
Baa2
AGC
BBB-
Baa2
BBB
Baa2
BBB+
Stand-Alone Transmission:
FET
Baa2
BBB+
Baa2
BBB+
ATSI
MAIT
TrAIL
KATCo
(1) S = Stable, P = Positive
On December 23, 2025, S&P upgraded FE's corporate credit rating to BBB+ from BBB and its senior unsecured rating to BBB from BBB-, and upgraded each subsidiaries’ corporate credit rating and senior unsecured rating, as applicable, one notch, excluding TE, MP, AGC and PE whose ratings were affirmed. S&P also revised the outlook of FE and its subsidiaries’ to stable except for MP and PE whose outlooks were revised to positive and AGC whose outlook remained unchanged at stable.
On September 23, 2025, Fitch upgraded FE PA’s corporate credit rating to A- from BBB+, its senior unsecured rating to A from A- and updated its ratings outlook to stable. Additionally, Fitch affirmed the ratings and outlooks of FE and its other subsidiaries.
The applicable undrawn and drawn margin on the credit facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments and on actual borrowings under the credit facilities are based on FE’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, 2025, FirstEnergy could incur approximately $0.9 billion of incremental interest expense or incur an approximate $2.4 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.
As of December 31, 2025, JCP&L could incur approximately $6.4 billion of additional debt or incur an approximate $3.5 billion reduction to equity, as defined under the debt to capital covenant, and JCP&L would remain within the limitations of the financial covenant requirements of JCP&L's credit facility.
Cash Requirements and Commitments
The Registrants have 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, 2025 (Undiscounted):
Total
Thereafter
FirstEnergy
(In millions)
Long-term debt (1)
Short-term borrowings
Interest on long-term debt
Operating leases (2)
Finance leases (2)
Fuel and purchased power (3)
Committed investments (4)
Pension funding
Total - FirstEnergy
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases.
(2) See Note 7., "Leases," of the Combined Notes to Financial Statements of the Registrants .
(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.
As of December 31, 2025 (Undiscounted):
Total
Thereafter
JCP&L
(In millions)
Long-term debt (1)
Short-term borrowings
Interest on long-term debt
Operating leases (2)
Finance leases (2)
Committed investments (3)
Total - JCP&L
(1) Excludes unamortized discounts and premiums.
(2) See Note 7., "Leases," of the Combined Notes to Financial Statements of the Registrants.
(3) Amounts represent committed capital expenditures and other capital-like investments that earn a return.
Excluded from the tables 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 $4.8 billion ($1.5 billion at JCP&L) in 2026.
The tables above also exclude AROs, reserves for litigation, injuries and damages and environmental remediation since the amount and timing of the cash payments are uncertain. The tables also exclude 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 8.0% for 2026, is expected to be approximately $250 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily. JCP&L is not expected to make a contribution.
Changes in Cash Position
As of December 31, 2025, FirstEnergy had $57 million of cash and cash equivalents and $42 million of restricted cash compared to $111 million of cash and cash equivalents and $43 million of restricted cash as of December 31, 2024, on the Consolidated Balance Sheets.
The following table summarizes the major classes of cash flow items:
For the Years Ended December 31,
(In millions)
Net cash provided from operating activities
Net cash used for investing activities
Net cash provided from financing activities
Net change in cash, cash equivalents and restricted cash
Cash, cash equivalents, and restricted cash at beginning of period
Cash, cash equivalents, and restricted cash at end of period
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 $3,700 million during 2025, $2,891 million during 2024, and $1,387 million during 2023. The increase in cash from operating activities in 2025 from 2024 is primarily due to:
• Higher revenues from the implementation of base rate cases in Pennsylvania, New Jersey, and West Virginia;
• Higher return on regulated capital investment programs;
• Higher net transmission revenue collection based on the timing of formula rate collections;
• Higher customer usage and demand, primarily due to colder weather temperatures in the first and fourth quarters of 2025;
• Increased working capital due to higher accounts receivable receipts, timing of accounts payable disbursements, and lower employee benefit payments;
• Lower federal income tax payments due to the absence of tax payments in 2024 related to the FET Equity Interest Sale; and
• Absence of the payment of the SEC civil penalty and OAG settlement in the third quarter of 2024.
The increase in cash provided from operating activities was partially offset by:
• The absence of net proceeds from the shareholder derivative lawsuit settlement in the second quarter of 2024;
• Temporary rate credits that were provided to JCP&L residential customers during the third quarter of 2025, net of recoveries, as further discussed below;
• Lower dividend distribution received by FEV from its equity investment in Global Holding; and
• Decreased cash collateral received from suppliers due to changes in power prices.
Cash Flows From Investing Activities
Net cash used for investing activities in 2025 principally represented cash used for capital investments. The following table summarizes net cash used for investing activities for the years ended 2025, 2024 and 2023:
For the Years Ended December 31,
Investing Activities
(In millions)
Capital Investments:
Distribution Segment
Integrated Segment
Stand-Alone Transmission Segment
Corporate / Other
Asset removal costs
Other
Net cash used for investing activities during 2025 increased $715 million, compared to 2024, primarily due to higher planned capital investment spend.
Cash Flows From Financing Activities
Net cash provided from financing activities was $1,310 million, $1,434 million, and $2,238 million in 2025, 2024, and 2023, respectively. The following table summarizes financing activities for the years ended 2025, 2024, and 2023.
For the Years Ended December 31,
Financing Activities
(In millions)
New Issues
Senior unsecured notes
Unsecured convertible notes
FMBs
Senior secured notes
Redemptions / Repayments
Unsecured convertible notes
Senior unsecured notes
FMBs
Senior secured notes
Proceeds from FET Equity Interest Sale (Note 1.)
Noncontrolling interest cash distributions
Short-term borrowings, net
Common stock dividend payments
Debt issuance and redemption costs, and other
During the year ended December 31, 2025, FirstEnergy had the following redemptions and issuances:
Company
Type
Redemption/Issuance Date
Interest Rate
Maturity
Amount
(In millions)
Description
Redemptions
Senior Unsecured Notes
March, 2025
FE redeemed unsecured notes that became due.
TrAIL
Senior Unsecured Notes
May, 2025
TrAIL redeemed unsecured notes that became due.
TrAIL
Senior Unsecured Notes
June, 2025
TrAIL redeemed unsecured notes that became due.
Senior Unsecured Convertible Notes
June, 2025
FE repurchased approximately $1,206 million of the principal amount of its 2026 Convertible Notes for $1,225 million, including a premium of approximately $19 million.
JCP&L
Senior Unsecured Notes
October, 2025
On October 16, 2025, JCP&L redeemed $650 million of 4.30% senior notes due 2026.
Senior Unsecured Notes
December, 2025
On December 31, 2025, FE redeemed $300 million of 1.60% senior notes due 2026.
Issuances
TrAIL
Senior Unsecured Notes
April, 2025
Proceeds were used to redeem senior notes that came due in 2025, to refinance existing debt, for working capital, and for other general corporate purposes.
ATSI
Senior Unsecured Notes
May, 2025
Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.
Senior Unsecured Notes
May, 2025
Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.
MAIT
Senior Unsecured Notes
June, 2025
Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.
FMBs
June, 2025
Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.
Senior Secured Notes
June, 2025
Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.
Senior Unsecured Convertible Notes
June, 2025
Proceeds were used to refinance existing debt, to repurchase a portion of its 2026 Convertible Notes, and for other general corporate purposes.
Senior Unsecured Convertible Notes
June, 2025
Proceeds were used to refinance existing debt, to repurchase a portion of its 2026 Convertible Notes, and for other general corporate purposes.
FET
Senior Unsecured Notes
August, 2025
Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.
JCP&L
Senior Unsecured Notes
September, 2025
Proceeds were used to refinance existing debt, including the repayment of the remaining $650 million aggregate principal amount of JCP&L’s 4.30% senior notes due 2026, to finance capital expenditures, and for other general corporate purposes.
JCP&L
Senior Unsecured Notes
September, 2025
Proceeds were used to refinance existing debt, including the repayment of the remaining $650 million aggregate principal amount of JCP&L’s 4.30% senior notes due 2026, to finance capital expenditures, and for other general corporate purposes.
JCP&L
Senior Unsecured Notes
September, 2025
Proceeds were used to refinance existing debt, including the repayment of the remaining $650 million aggregate principal amount of JCP&L’s 4.30% senior notes due 2026, to finance capital expenditures, and for other general corporate purposes.
FE Convertible Notes Issuance
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. 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.
Through 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. FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash for the aggregate
principal amount of the 2026 Convertible Notes being converted and its conversion obligation in excess of such aggregate principal amount.
The amount of consideration that a holder will receive upon conversion will be determined by reference to the volume-weighted average price of FE’s common stock for each trading day in a 40 trading day observation period. For any conversions on or after February 1, 2026, this period would be the 40 consecutive trading days beginning on, and including, the 41st scheduled trading day immediately preceding the maturity date.
On June 12, 2025, FE issued $1.35 billion aggregate principal amount of its 2029 Convertible Notes and $1.15 billion aggregate principal amount of its 2031 Convertible Notes.
The 2029 Convertible Notes and 2031 Convertible Notes bear interest at a rate of 3.625% per year and 3.875% per year, respectively, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. The 2029 Convertible Notes and 2031 Convertible Notes are unsecured and unsubordinated obligations of FE and will mature on January 15, 2029 and January 15, 2031, respectively, unless earlier converted or repurchased in accordance with their terms.
The notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $2.47 billion, net of issuance costs.
Holders may convert notes at their option at any time prior to the close of business on the business day immediately preceding: (i) October 15, 2028, with respect to the 2029 Convertible Notes, and (ii) October 15, 2030, with respect to the 2031 Convertible Notes, only under certain 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 2029 Convertible Notes and 2031 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 2029 Convertible Notes and 2031 Convertible Notes.
On or after October 15, 2028, in the case of the 2029 Convertible Notes, and on or after October 15, 2030, in the case of the 2031 Convertible Notes, until the close of business on the second scheduled trading day immediately preceding the maturity date of the relevant series of notes, holders may convert all or any portion of their notes of such series at any time, regardless of the foregoing conditions. FE will settle conversions of such notes by paying cash up to the aggregate principal amount of the notes to be converted and paying or delivering, as the case may be, cash, shares of its common stock or a combination of cash and shares of its common stock, at its election, in respect of the remainder, if any, of its conversion obligation in excess of the aggregate principal amount of the notes being converted, subject to the applicable terms of the indentures.
The conversion rate for each of the series of notes will initially be 20.9275 shares of FE’s common stock per $1,000 principal amount of such notes (equivalent to an initial conversion price of approximately $47.78 per share of FE’s common stock). The initial conversion price of such 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 June 9, 2025. 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. In addition, following certain corporate events that occur prior to the maturity date with respect to a series of notes (and, in the case of the 2031 Convertible Notes, if FE delivers a notice of redemption with respect to the 2031 Convertible Notes), FE will, in certain circumstances, increase the conversion rate for a holder who elects to convert its notes of such series in connection with such corporate event or redemption as applicable.
FE may not redeem the 2029 Convertible Notes prior to the maturity date of the 2029 Convertible Notes. On or after January 15, 2029 and prior to the 40th trading day immediately before the maturity date of the 2031 Convertible Notes, FE may redeem for cash all or any of the portion of the 2031 Convertible Notes, subject to certain partial redemption limitations and only under certain conditions.
If FE undergoes a fundamental change (as defined in the relevant indenture), subject to certain conditions, holders of the 2026 Convertible Notes, 2029 Convertible Notes and/or 2031 Convertible Notes may require FE to repurchase for cash all or any portion of their notes at a repurchase price equal to 100% of the principal amount of the 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, following certain corporate events that occur prior to the maturity date with respect to a series of convertible notes (and, in the case of the 2031 Convertible Notes, if FE delivers a notice of redemption with respect to the 2031 Convertible Notes), FE will, in certain circumstances, increase the conversion rate for a holder who elects to convert its notes of such series in connection with such corporate event or redemption, as applicable.
Separate from the issuance of the 2029 Convertible Notes and 2031 Convertible Notes, FE repurchased approximately $1.2 billion aggregate principal amount of the 2026 Convertible Notes, using a portion of the proceeds from the offering of the 2029 Convertible Notes and 2031 Convertible Notes described above. FE may, in the future, effect additional repurchases of remaining outstanding 2026 Convertible Notes.
FET Senior Notes and Registration Rights
On August 13, 2025, FET issued $450 million of senior unsecured notes due in 2033, in a private offering that included a registration rights agreement in which FET agreed to conduct an exchange offer of these senior notes for the like principal amounts registered under the Securities Act within 366 days of closing of the offering. On November 4, 2025, FET filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on December 3, 2025. On January 21, 2026, FET completed the exchange offer of these senior notes for like principal amounts registered under the Securities Act.
JCP&L Senior Notes and Registration Rights
On December 5, 2024, JCP&L issued $700 million of senior unsecured notes due in 2035 in a private offering that included a registration rights agreement in which JCP&L agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act. On April 1, 2025, JCP&L filed a registration statement on Form S-4 with the SEC, which became effective on April 11, 2025.
On September 4, 2025, JCP&L issued: (i) $350 million of senior unsecured notes due in 2029; (ii) $500 million of senior unsecured notes due in 2031; and (iii) $500 million of senior unsecured notes due in 2036, 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 the like principal amounts registered under the Securities Act within 366 days of closing of the offering.
FE or its affiliates may, from time to time, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as FE or its affiliates may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors.
FIRSTENERGY - GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2025, outstanding guarantees and other assurances aggregated approximately $1.1 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($614 million) and other assurances ($439 million).
In 2025, FET, DominionHV and Transource issued an equity support agreement to enable Valley Link to enter into a credit facility with a third party. The equity support agreement expires once all Valley Link credit agreement obligations are satisfied or when FET has fulfilled its support obligations under the equity support agreement. As of December 31, 2025, the fair value of FET’s support obligations relating to the Valley Link credit facility was immaterial.
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, 2025, $185 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $33 million of net cash collateral as of December 31, 2025, from certain generation suppliers, and such amount is included in "Other current liabilities" on FirstEnergy's Consolidated Balance Sheets.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. See Note 14., "Commitments, Guarantees and Contingencies," of the Combined Notes to Financial Statements of the Registrants for more information.
JCP&L - GUARANTEES AND OTHER ASSURANCES
JCP&L has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include stand-by LOCs and surety bonds. JCP&L enters into these arrangements to facilitate
commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments JCP&L could be required to make under these guarantees as of December 31, 2025, was $48 million.
Collateral and Contingent-Related Features
In the normal course of business, JCP&L may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require JCP&L to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon JCP&L's credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
JCP&L has posted $28 million of collateral in the form of LOCs as of December 31, 2025. JCP&L is holding $2 million of net cash collateral as of December 31, 2025, from certain generation suppliers, and such amount is included in "Other current liabilities" on JCP&L's Balance Sheets.
These credit-risk-related contingent features stipulate that if JCP&L were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. See Note 14., "Commitments, Guarantees and Contingencies," of the Combined Notes to Financial Statements of the Registrants for more information.
MARKET RISK INFORMATION
FirstEnergy may use 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, 2025, FirstEnergy has a net asset of $20 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, 2025, the FirstEnergy pension plan assets were allocated approximately as follows: 33% in public equity securities, 25% in fixed income securities, 5% in hedge funds, 8% in real estate, 22% in private debt/equity and 7% 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 8.0% for 2026, is expected to be approximately $250 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily. JCP&L is not expected to make a contribution.
As of December 31, 2025, FirstEnergy's OPEB plan assets were allocated approximately as follows: 57% in equity securities, 23% in fixed income securities and 20% in cash and short-term securities. See Note 4., "Pension and Other Postemployment Benefits," of the Combined Notes to Financial Statements of the Registrants for additional details on FirstEnergy's pension and OPEB plans.
During 2025, FirstEnergy's pension plan assets have gained approximately 15.4% as compared to an annual expected return on plan assets of 8.5%, and FirstEnergy's OPEB plan assets have gained approximately 15.7% as compared to an annual expected return on plan assets of 7.0%.
Interest Rate Risk
The Registrants' exposure to fluctuations in market interest rates is largely mitigated as all long-term debt, with the exception of the credit facilities, has fixed interest rates, as noted in the table below. However, the Registrants are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities.
FirstEnergy - Comparison of Carrying Value to Fair Value as of December 31, 2025
Year of Maturity or Notice of Redemption
There-after
Total
Fair Value
(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income
Average interest rate
Liabilities:
Long-term Debt:
Fixed rate
Average interest rate
JCP&L - Comparison of Carrying Value to Fair Value as of December 31, 2025
Year of Maturity or Notice of Redemption
There-after
Total
Fair Value
(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income
Average interest rate
Liabilities:
Long-term Debt:
Fixed rate
Average interest rate
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs during the year, however, future years could be impacted by changes in the market.
FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of December 31, 2025, the spot rate was 5.59% and 5.37% for pension and OPEB obligations, respectively, as compared to 5.72% and 5.60% as of December 31, 2024, respectively.
Each of the Amended Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates.
Economic Conditions
While supply lead times have not fully returned to levels prior to the COVID-19 pandemic, FirstEnergy continues to monitor the situation in light of demand increases across the industry, including due to data center usage, and the imposition of tariffs and
retaliatory tariffs that have been, and may be, imposed by the U.S. government in response. FirstEnergy continues to implement mitigation strategies to address supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, the situation remains fluid, and a prolonged continuation or further increase in demand, or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.
CREDIT RISK
Credit risk is the risk that the Registrants would incur a loss as a result of nonperformance by counterparties of their contractual obligations. The Registrants maintain 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. The Registrants have concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact the Registrants' 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. The Registrants’ credit policies to manage credit risk include the use of an established credit approval process and daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries, including JCP&L, may request additional credit assurance, in certain circumstances, in the event that the counterparties' (i) credit ratings fall below investment grade, (ii) tangible net worth falls below specified percentages, or (iii) exposures exceed an established credit limit.
OUTLOOK
INCOME TAXES
During 2025, FERC issued orders to a non-affiliate concluding that, based on certain previously issued IRS private letter rulings, certain NOL carryforward deferred tax assets, as computed on a separate return basis, should be included in rate base for ratemaking purposes. FirstEnergy determined in the third quarter of 2025 that these rulings and orders also would apply to certain of its subsidiaries, resulting in a benefit from a reduction in regulatory liabilities, reflected as the remeasurement of excess deferred income taxes, and an increase in accumulated deferred income tax assets for ratemaking purposes, which will increase overall rate base. FirstEnergy made the appropriate updates in its annual formula rates for the impacted subsidiaries. See Note 6., “Taxes,” of the Combined Notes to Financial Statements of the Registrants. FirstEnergy will continue to evaluate whether regulatory filings are required in other jurisdictions to implement similar adjustments to NOL carryforward deferred tax assets for ratemaking purposes.
On July 4, 2025, President Trump signed into law the OBBBA, which, among other things, makes permanent certain corporate tax incentives that were set to expire in the TCJA, and terminates tax credits for most wind and solar projects placed in service after 2027. Because many of the provisions of the TCJA will be continued under the OBBBA, and as FirstEnergy is not materially impacted by tax incentives associated with wind and solar projects, FirstEnergy does not expect to be materially impacted by the OBBBA.
On September 30, 2025, the IRS issued additional guidance on the corporate AMT. While FirstEnergy continues to believe, more likely than not, it will be subject to corporate AMT, additional IRS guidance or revised U.S. Treasury regulations, which are expected to be issued in the future, as well as potential tax legislation or presidential executive orders could provide certain adjustments to regulated utilities in calculating corporate AMT, which may reduce or otherwise significantly change FirstEnergy’s AMT estimates or its conclusions as to whether it is an AMT payer. JCP&L is party to an intercompany income tax allocation agreement with FirstEnergy and, accordingly, may be allocated a share of any corporate AMT paid by the FirstEnergy consolidated tax group. Any adverse developments concerning corporate AMT liability, including guidance from the U.S. Treasury and/or the IRS or unfavorable regulatory treatment by FERC and/or applicable state regulatory authorities, could negatively impact FirstEnergy’s cash flows, results of operations and financial condition.
STATE REGULATION
Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
The following table summarizes the key terms of state base rate orders in effect for the Electric Companies as of December 31, 2025:
Company
Rates Effective For Customers
Allowed Debt/Equity Capital Structure
Allowed ROE
CEI (1)
May 2009
January 2025
Settled (2)
Settled (2)
March 2024
Settled (2)
JCP&L
June 2024
January 2009
PE (West Virginia)
March 2024
Settled (2)
PE (Maryland)
October 2023
January 2009
(1) On November 19, 2025, the PUCO issued an order in the Ohio Companies’ base rate case that authorized a capital structure of 48.8% debt and 51.2% equity, and an ROE of 9.63%. New rates reflecting this order were not yet in effect as of December 31, 2025.
(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, following passage of the Climate Solutions Now Act of 2022, required annual incremental energy efficiency targets of 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally, at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million, which the MDPSC approved on December 27, 2024. PE recovers EmPOWER Maryland program costs with carrying costs on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Lost distribution revenue attributable to energy efficiency or demand reduction is recovered only through base rates. Consistent with an MDPSC order dated December 29, 2022, phasing out the unamortized balances of EmPOWER Maryland investments, PE is required to expense 67% of its EmPOWER Maryland program costs in 2025, and 100% in 2026 and beyond. All previously unamortized costs for prior cycles are to be collected by the end of 2030, consistent with the 2024-2026 order issued on December 29, 2023. Legislation which took effect on July 1, 2024 is expected to reduce the carrying costs on the EmPOWER Maryland 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 Maryland surcharge rates for PE in accordance with the new law, denying PE’s request for a hearing that sought to challenge certain portions of the law. On August 30, 2024, PE filed a petition seeking judicial review of its challenge to the law in the Circuit Court for Washington County, Maryland. On August 6, 2025, the Circuit Court for Washington County, Maryland issued an order granting PE’s petition, finding that the legislature may not change terms to apply retroactively to monies already expended. MDPSC and the Maryland Office of People’s Counsel have each appealed the decision. On November 14, 2025, the Appellate Court of Maryland issued an order denying the unopposed motion of the Attorney General of Maryland to Intervene without prejudice to the ability to file an amicus curiae brief, which the Attorney General filed on December 30, 2025. PE's response brief was filed on January 21, 2026.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L and one other party filed comments on July 31, 2023. On July 16, 2025, the NJBPU issued its final order,
directing 100 of the 105 recommendations be implemented, including certain modifications. JCP&L filed its implementation plan on September 22, 2025, and began quarterly progress reporting in October 2025.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US LLC and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023.
On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. On January 30, 2025, and February 25, 2025, Shell New Energies US LLC and EDF Renewables North America respectively announced that each was exiting its Atlantic Shores partnership to construct wind energy off the shore of New Jersey. On June 4, 2025, Atlantic Shores filed a petition with the NJBPU, requesting consent to terminate its 1.5 GW offshore wind project. These cancellations are not expected to directly affect JCP&L’s awarded projects.
On May 23, 2025, JCP&L filed with the NJBPU a motion seeking declaratory guidance in view of recent offshore wind developments, including a shift in federal energy policy toward more traditional energy resources. JCP&L requested that the NJBPU provide guidance either affirming the current project schedule or, alternatively, authorizing JCP&L to modify the schedule. On June 9, 2025, responses to JCP&L’s motion were filed with the NJBPU, including a cross-motion by the New Jersey Division of Rate Counsel to reopen the offshore wind transmission proceeding, which JCP&L opposed. JCP&L advised that it intended to comply with its contractual obligations to construct the transmission project, and that its motion was limited to seeking guidance on the construction milestones. On July 28, 2025, the New Jersey Division of Rate Counsel asked the NJBPU to take judicial notice of a recent NYPSC order terminating its offshore wind transmission infrastructure process in the interest of protecting ratepayers. On August 13, 2025, the NJBPU issued an order requesting that JCP&L delay expenditures of certain of the transmission investment planned by JCP&L for a 2.5-year period, and directing that JCP&L work with NJBPU staff and PJM to ensure alignment as to the work that is to be continued on the original timeline and the work that is to be delayed consistent with the order.
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 initiated a due diligence review of the application shortly thereafter. On January 16, 2025, the DOE announced a conditional commitment to JCP&L for a loan guarantee of up to approximately $716 million for the project. On August 20, 2025, the DOE terminated its conditional commitment to JCP&L due to the DOE’s determination that a condition precedent could not be satisfied.
On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. On April 10, 2025, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s amended EnergizeNJ petition, which the NJBPU approved on April 23, 2025. The settlement provides for total program costs of $339 million, including capital investments in JCP&L’s electric distribution system of approximately $203 million, $132 million of matching capital investment and approximately $4 million of O&M expense. Pursuant to the settlement, the program began on July 1, 2025, and will continue through December 31, 2028. JCP&L has agreed to file a base rate case no later than January 1, 2030.
In February 2025, the NJBPU certified the results of its annual basic generation service auctions through which New Jersey’s four EDCs – including JCP&L – satisfy their generation supply requirements for BGS customers for the period beginning June 1, 2025 through May 31, 2026. The certified results resulted in significant rate increases for New Jersey EDC customers and, by order dated April 23, 2025, the NJBPU directed the four EDCs to submit proposals to mitigate the impact of the rate increases
that affected residential customers beginning June 1, 2025. On May 7, 2025, JCP&L filed a petition in response to the April 2025 order, modeling four potential mitigation scenarios. On June 18, 2025, the NJBPU approved a stipulation that included JCP&L, NJBPU Staff and New Jersey Division of Rate Counsel, pursuant to which, among other things, JCP&L agreed to apply a temporary rate credit of $30.00 to each residential electric customer’s monthly bill in July and August 2025 that would be deferred in a regulatory asset and recovered with a charge of $10 applied to each residential bill from September 2025 through February 2026 to recover the amounts deferred, without carry charges, subject to a final reconciliation. As of December 31, 2025, JCP&L's regulatory asset associated with this temporary rate credit was approximately $20 million.
On August 13, 2025, the NJBPU issued an Order to Show Cause reviewing JCP&L’s 2024 Annual System Performance Report, which includes information regarding JCP&L’s systems level of electric service reliability performance during the prior calendar year. Failure to attain NJBPU’s minimum reliability levels may subject JCP&L to a penalty. The NJBPU order alleges JCP&L has failed to achieve minimum reliability levels for calendar years 2022, 2023, and 2024, and directed JCP&L to file an answer demonstrating why the NJBPU should not impose certain penalties upon JCP&L for such failure, which JCP&L filed on October 10, 2025. JCP&L is unable to predict the outcome or estimate the impact of this matter.
On January 14, 2026, the NJBPU issued an order authorizing JCP&L to modify its Lost Revenue Adjustment Mechanism rate rider in its tariff. The modification allows JCP&L to recover the revenue impact of sales losses of approximately $16 million (pre-tax) primarily resulting from the implementation of JCP&L’s Energy Efficiency and Conservation Plan during the one-year period from July 1, 2023, through June 30, 2024. The modification was effective February 1, 2026.
OHIO
Until the rates approved in the 2024 base rate case go into effect, the Ohio Companies will continue to 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, 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 April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV. On May 22, 2025, the Ohio Supreme Court granted the Ohio Companies motion to intervene in the appeal. On July 7, 2025, OCC and NOAC filed their Appellants’ brief. Appellees, including the PUCO and the Ohio Companies, filed their briefs on August 26, 2025, to which OCC and NOAC replied on September 15, 2025.
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 proposed to continue providing power to non-shopping customers at market-based prices set through an auction process, and proposed to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual reliability performance-based revenue cap increases of $37 million to $43 million, and an AMI rider for recovery of approved grid modernization investments. ESP VI additionally proposed 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 proposed energy efficiency programs for low-income customers, and included 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. On May 15, 2025, the Ohio Governor signed HB 15, which repealed the statute authorizing ESPs in Ohio, effective August 14, 2025. On December 17, 2025, the PUCO dismissed the Ohio Companies’ application for ESP VI due to the repeal of the ESP statute.
On March 14, 2025, as directed by the PUCO in its December 18, 2024, order approving the Ohio Companies’ revised ESP IV tariffs, the Ohio Companies filed with the PUCO a request to commence their statutorily required quadrennial review of ESP IV and establish a proposed schedule. On July 10, 2025, the Ohio Companies withdrew the request for the PUCO to establish a procedural schedule following the May 15, 2025 signing by the Ohio Governor of HB 15 ending the statutory mandate to conduct the quadrennial review, effective August 14, 2025. The OCC filed its response to the Ohio Companies’ notice of withdrawal on July 25, 2025, to which the Ohio Companies replied on August 1, 2025. The matter remains pending before the PUCO.
On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing included 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 incorporated 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. On November 19, 2025, the PUCO issued an order in the rate case lifting the rate freeze and approving a net increase in base distribution revenues of the Ohio Companies of approximately $34 million, with a return on equity of 9.63% and a hypothetical capital structure of 48.8% debt and 51.2% equity for all three Ohio Companies, which reflects a roll-in of current riders such as DCR and AMI. The PUCO authorized continuance of Rider DCR with a cap increase commensurate with capital investments through January 31, 2025, and approved the Ohio Companies’ proposal to change pension and OPEB recovery to the delayed recognition method. Additionally, the order authorizes recovery of certain deferred costs for storm restoration, operations and maintenance, and energy efficiency programs. As a result of the order, the Ohio Companies recognized a $352 million pre-tax impairment charge related to future recovery disallowances of certain previously capitalized amounts. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025 base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On January 9, 2026, the Ohio Companies filed an expedited motion for ruling on the proposed compliance tariffs and on February 4, 2026, PUCO staff issued a letter recommending that most of the Ohio Companies’ proposed compliance tariffs be approved. The Ohio Companies cannot predict the outcome of the rehearing, but do not expect material changes to the November 2025 order.
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. On May 15, 2025, the Ohio Companies filed their SEET application for determination of the existence of significantly excessive earnings under ESPs IV and V for calendar year 2024. Each application demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. These matters remain pending before the PUCO.
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 were further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities until August 14, 2025, at which time HB 15 became effective and the Ohio Companies stopped collecting OVEC-related charges. The Ohio Companies contested the motions, which are pending before the PUCO.
In 2020, the four proceedings below were opened by the PUCO relating to HB 6. The matters, described in full below, were resolved pursuant to the terms of an order issued by the PUCO on January 7, 2026. The order, which adopted without
modification the terms of the stipulation and recommendation filed with the PUCO by the Ohio Companies and fourteen intervenors on December 19, 2026, vacated the approximately $250 million in monetary penalties assessed by the PUCO in its order issued on November 19, 2025. Instead, the January 7, 2026 PUCO order directed the Ohio Companies to pay their customers, among other things, restitution and refunds totaling approximately $275 million ($213 million after-tax), of which, $25 million is recorded in "Other current liabilities" and approximately $250 million is recorded within "Regulatory Liabilities" on FirstEnergy's Consolidated Balance Sheets. The refunds will be paid out over three billing cycles beginning in February 2026 and the matters are now resolved:
• 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 were held between June 10, 2025, and June 27, 2025. Initial and reply briefs were filed by the parties on July 21, 2025, and August 4, 2025, respectively.
• 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 $15,000. 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 $15,000 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. On September 5, 2025, the administrative law judge set a procedural schedule, but stayed it on December 29, 2025.
• 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 allegedviolations 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 were later addressed in hearings held between June 10, 2025, and June 27, 2025, as further described below. Initial and reply briefs have been filed by the Ohio Companies, PUCO staff and the intervening parties.
• 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 were held between June 10, 2025, and June 27, 2025. Initial and reply briefs were filed by the parties on July 21, 2025, and August 4, 2025, respectively.
See “Outlook - Other Legal Proceedings” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.
PENNSYLVANIA
FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025. FE PA operates under rates approved by the PPUC, effective as of January 1, 2025. FE PA operates under a DSP through the May 31, 2027 delivery period, which provides for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service.
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 cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.
On November 26, 2025, FE PA submitted a petition for approval of its Phase V Energy Efficiency and Conservation Plan, which includes energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.01% MW, and energy consumption reduction targets, as a percentage of FE PA’s historic 2009 to 2010 reference load, at 2.00% MWh. The proposed plan includes cost recovery of approximately $390 million to be recovered through its Phase V Energy Efficiency and Conservation Charge Rider and runs for a five-year period beginning June 1, 2026, through May 31, 2031. Hearings were held on January 29, 2026. The parties have reached a full settlement in principle and expect to file with the PPUC a Joint Petition for Complete Settlement on or before February 19, 2026. An order is expected from the PPUC in the first quarter of 2026.
On February 3, 2026, FE PA filed a proposed DSP for provision of generation for the June 1, 2027 through May 31, 2031 delivery period, to be sourced through competitive procurements for customers who do not receive service from an alternative EGS. Under the 2027-2031 DSP, supply would be provided through a mix of 12, 24, and in the case of residential customers, 60-month energy contracts, as well as spot market purchases for industrial customers. A final order is expected from the PPUC by November 2026.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective March 27, 2024. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually and MP and PE filed their ENEC filing on August 29, 2025, for rates effective January 1, 2026.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024. Two of the five solar generation sites went into service in 2024, with the third in April 2025. 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. In November 2025, MP and PE submitted a settlement agreement to the WVPSC seeking approval to adjust the solar surcharge rate, which was approved without modification on January 15, 2026. Pursuant to the settlement agreement, a modest decrease in the solar surcharge rate became effective January 15, 2026.
On August 29, 2025, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates by approximately $14 million, proposed to be effective January 1, 2026, which represents a 0.8% increase of total revenues. The proposed increase is driven primarily by an under-recovery balance as of June 30, 2025, and higher costs for fuel and reagents. On December 12, 2025, the parties filed a settlement agreement with the WVPSC, which was approved in full without modification on December 23, 2025.
On August 29, 2025, MP and PE filed with the WVPSC their biennial review of their vegetation management program and surcharge. MP and PE have proposed an approximate $3.2 million decrease in the surcharge rates due to an over-recovery balance as of June 30, 2025, and higher costs for fuel and reagents. The WVPSC held a hearing regarding rate matters on December 15, 2025. An order from the WVPSC is expected by the end of first quarter 2026.
On October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC. To ensure that MP and PE can meet their PJM adequacy requirements, the plan proposes, among other things, near-term market capacity purchases, and the addition of 70 MWs of solar generation by 2028 and 1,200 MWs of natural gas combined cycle generation by 2031. On November 26, 2025, the WVPSC issued a procedural order setting a hearing in May 2026.
On February 13, 2026, MP and PE filed a CPCN to construct and operate a 1,200 MW combined cycle gas turbine plant and 70 MWs of solar generation capacity for an estimated capital investment totaling approximately $2.7 billion as of the date of the filing. The request also includes a surcharge designed to recover financing costs during development and construction of the projects, as well as to transition to recovery in base rates once the projects are placed in-service and approved through a base rate case. An order is expected from the WVPSC in the second half of 2026. See “Outlook - Environmental Matters - Clean Water Act" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" 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.
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, 2025:
Company
Allowed Debt/Equity Capital Structure
Allowed ROE
ATSI
Actual (13-month average)
JCP&L
Actual (13-month average)
Lower of Actual (13-month average) or 56% equity
Lower of Actual (13-month average) or 56% equity
KATCo (2)
49.3% equity (3)
MAIT
Lower of Actual (13-month average) or 60% equity
TrAIL
Actual (year-end)
(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 ).
(2) On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
(3) 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. The Electric Companies and AE Supply are required to renew their respective authorizations every three years, and on December 16, 2025, the companies filed applications for the next renewal period.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On
February 4, 2022, FERC filed the final audit report for the period of January 1, 2015, through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy reclassified certain transmission capital assets to operating expenses for the audit period. FirstEnergy fully recovered approximately $105 million ($13 million at JCP&L) of these costs reclassified to operating expenses in its transmission formula rate revenue requirements as of December 31, 2024.
On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates and a since terminated fuel consulting contract, were being referred to other offices within FERC for further review. On July 5, 2024, and September 26, 2024, the FERC Office of Enforcement issued additional data requests related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. On September 10, 2024, and January 13, 2025, the FERC Office of Enforcement issued further data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy responded. The FERC Office of Enforcement took no action with respect to the referred matters, and on December 23, 2025, FERC staff notified FirstEnergy that the audit is concluded.
Transmission ROE Incentive
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliate and American Electric Power Service Corporation, and Duke Energy Ohio, Inc. 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 Energy Ohio, Inc., but granted it as to AEP’s Ohio affiliate. AEP’s Ohio affiliate 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’s Ohio affiliate rates, but not from the Duke Energy Ohio, Inc. and ATSI rates. During 2024, as a result of the ruling, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the FirstEnergy Consolidated Statements of Income at the Stand-Alone Transmission segment, to reflect the expected refund owed to transmission customers back to February 24, 2022. On June 20, 2025 and June 24, 2025, ATSI and AEP’s Ohio affiliate, respectively, applied for the Supreme Court of the U.S. to review the Sixth Circuit’s decision. On November 10, 2025, the Supreme Court of the U.S. denied ATSI’s petition for the court to review the case. On November 13, 2025, the Sixth Circuit issued a mandate sending the case back to FERC for further proceedings.
Transmission ROE Methodology
A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 and remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis; provided however, due to the Sixth Circuit’s ruling in the Transmission ROE Incentive matter described above, ATSI is collecting the ROE incentive adder subject to refund.
Transmission Planning Supplemental Projects
On September 27, 2023, the OCC filed a complaintagainst ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. Subsequently, intervenors expanded the scope of this proceeding to all of the transmission utilities in PJM, including JCP&L. ATSI and the other transmission utilities in Ohio and PJM filed comments.
Local Transmission Planning Complaint
On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates. The complaint demands that FERC: (i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100 kV or higher; (ii) appoint “independent transmission monitors” to conduct such planning; and (iii) condition construction of local transmission facilities on the facility having been planned by the “independent transmission monitor.” FirstEnergy is participating in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. FirstEnergy, together with the PJM transmission owners, filed a motion to dismiss the complaint on March 20, 2025, which is pending before FERC. FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy and its transmission capital investment strategy.
Ghiorzi v. PJM
In December 2023, PJM assigned certain baseline RTEP projects to NextEra Energy Transmission, which subsequently informed PJM that it would not construct the projects. On April 3, 2025, following the reassignment by PJM of certain baseline RTEP projects in Maryland and Virginia to PE, two individuals filed a complaint at FERC challenging this outcome, which FERC denied on February 2, 2026. The complainants asserted that PJM erred in reassigning the work to PE because such reassignment projects: (i) did not reflect the cost estimates or cost caps included in NextEra Energy Transmission’s bid; and (ii) would be constructed with different routing than as originally proposed. FirstEnergy and PE are unable to predict the outcome or estimate the impact that this complaint may have.
Valley Link Formula Transmission Rate
On March 14, 2025, the Valley Link joint venture filed an application for forward-looking formula transmission rates to provide for cost recovery for the portfolio of selected projects. Among other things, the transmission rate application provides for a capital structure of 40% debt and 60% equity, and a base ROE of 10.9% with associated templates and protocols, as well as transmission rate incentives, including the abandonment rate incentive, the CWIP rate incentive, the RTO participation adder incentive, the hypothetical capital structure incentive, and the precommercial regulatory asset incentive. On May 14, 2025, FERC issued an initial order that, among other things, accepted the requested abandonment rate incentive, CWIP rate incentive, RTO participation adder incentive, and precommercial regulatory asset rate incentive, and allowed the formula rate to go into effect on May 13, 2025, as requested, subject to refund, pending further settlement and hearing proceedings. The most recent settlement conference was held on December 9, 2025, at which the parties agreed to a procedural schedule to govern the next phase of the settlement process. The capital structure incentive and the other open rate design matters are being addressed in the confidential settlement negotiations.
Abandonment Transmission Rate Incentive
On February 26, 2025, PJM completed its 2024 RTEP Open Window 1 process and, among other actions, designated each of ATSI and PE to construct certain transmission projects. On July 11, 2025, ATSI and PE filed a joint application for the abandonment incentive with FERC, which, was approved on September 9, 2025. Effective September 10, 2025, ATSI and PE each became eligible to recover 50% of the project costs incurred prior to September 10, 2025, and 100% of the project costs incurred thereafter for any projects subsequently cancelled for reasons beyond the control of utility management.
PJM Capacity Market Reforms
On January 16, 2026, the Trump administration and the governors of all thirteen PJM states released a Statement of Principles Regarding PJM. This Statement of Principles is designed to, among other things, increase capacity available in the PJM market. PJM is seeking input from its stakeholders on matters related to the Statement of Principles, including: (1) proposals for a backstop capacity auction, price (cap), term, and quantity; (2) on whether to extend the existing capacity auction price collar; and (3) accelerating large load interconnections bringing their own generation. FirstEnergy is participating in the stakeholder processes that are described in the Statement of Principles, including by submitting a letter on January 30, 2026, in response to PJM’s request for input on the question of whether to extend the existing capacity auction price collar. In the letter, FirstEnergy supported extending the price collar but noted that PJM may wish to lower costs to customers by lowering the price collar through administrative or other mechanisms.
Large Load Interconnection Rulemaking
On October 23, 2025, the U.S. Secretary of Energy directed FERC to conduct a rulemaking procedure to develop regulations that would speed interconnection to the transmission system of large loads, including “Artificial Intelligence” data centers and “hybrid” data center/electric generation facilities. The Energy Secretary advanced 14 principles to guide this outcome, including that such large loads should be responsible for paying the costs of any network transmission system upgrades required for interconnection of such large loads, and that these large loads should have the option for building such network transmission upgrades. The Energy Secretary requested that FERC take final action by April 30, 2026. On October 27, 2025, FERC noticed
the Energy Secretary’s directive for comment, and subsequently established November 21, 2025 as the deadline for initial comments and December 5, 2025 as the deadline for reply comments. FET and its transmission affiliates, as well as over 150 other parties, filed comments on the established deadlines. FirstEnergy is unable to predict the outcome of this rulemaking procedure. To the extent the new regulations do not permit transmission utilities to fully recover costs associated with transmission network upgrades required to serve new large loads, our strategy of investing in transmission could be adversely affected.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate the Registrants with regard to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. While the Registrants’ environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. The Registrants cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact their business, results of operations, cash flows and financial condition. In general, environmental requirements applicable to the electric power sector are becoming increasingly prescriptive and stringent, and the EPA finalized a number of rules in 2024 that could impact the Registrants. However, the Trump administration has issued certain executive orders and stated its intention to rescind, revise or replace some existing environmental regulations and the ultimate impact of recently finalized rules, several of which are in litigation, and any replacement rules are uncertain.
On March 12, 2025, the EPA announced its intent to reevaluate or reconsider numerous environmental regulations, many of which apply to the Registrants. The specific timing or outcome of this initiative remains unknown, but regular required rulemaking processes and procedures still apply, and litigation is also anticipated to occur. The disclosures herein do not attempt to discern potential impacts of these deregulatory actions until and unless formal rulemaking or other regulatory actions are announced and the potential impacts to operations can be discerned.
The disclosures below apply to FirstEnergy and the disclosures under “Regulation of Waste Disposal,” are also applicable to JCP&L.
Clean Air Act
FirstEnergy complies with SO 2 and NO x 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 NO x and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NO x emissions to 1.2 million tons annually. CSAPR allows trading of NO x and SO 2 emission allowances between electric generation facilities located in the same state and interstate trading of NO x and SO 2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NO x and SO 2 emissions from electric generation facilities in 13 states, including West Virginia. This followed the 2014 Supreme Court of the U.S. ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NO x emissions from electric generation facilities 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 NO x 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 NO x 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 NO x 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 disapprovalsprecluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to
stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the Supreme Court of the U.S. Oral argument was heard on February 21, 2024. On June 27, 2024, the Supreme Court of the U.S. granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. On February 6, 2025, the EPA filed a motion at the D.C. Circuit to hold the proceedings in abeyance for 60 days to allow the EPA time to familiarize itself with the Good Neighbor Plan and in particular, time to brief the new administration about these consolidated petitions and the underlying Rule to allow them to decide what action, if any, is necessary. On March 10, 2025, the EPA filed a motion for remand with the D.C. Circuit identifying issues with the Good Neighbor Plan that make reconsideration appropriate. The D.C. Circuit granted the motion for remand and cancelled oral argument. Consistent with its March 12, 2025 announcement, the EPA intends to undertake reconsideration of the rule and complete any new rulemaking by the fourth quarter of 2026. On January 27, 2026, the EPA proposed phase 1 of its reconsideration of the rule applicable to eight states outside of FirstEnergy’s service area. FirstEnergy will continue to monitor any further actions by the EPA for any potential impact to its business and results of operations.
Climate Change
In recent years, certain regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. At the federal level, presidential administrations have held differing views on prioritizing actions to address GHG emissions and, by extension, climate change. Those differing views have led to policy changes, creating uncertainty about environmental requirements and associated impacts.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” known as the 2009 Endangerment Finding, 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 generation facilities. The 2009 Endangerment Finding is the basis of the EPA’s authority to regulate GHG emissions under the CAA.
In January 2025, Executive Order 14514 was issued and, among other deregulatory actions, directed the EPA Administrator to make recommendations on the “legality and continuing applicability” of the EPA’s 2009 Endangerment Finding, which forms the basis for the EPA's GHG regulations. On March 12, 2025, the EPA announced a series of planned deregulatory actions that it would be taking related to such executive order, including reconsideration of the regulations to limit power plant GHG emissions. On July 29, 2025, the EPA announced a proposal to rescind its 2009 Endangerment Finding. On February 12, 2026, the EPA issued a final rule rescinding its 2009 Endangerment Finding, thereby eliminating the basis for much of the EPA’s regulation of GHG emissions. However, depending on the outcome of any appeals and any future EPA actions, compliance with the GHG emissions limits could require additional capital expenditures or changes in operation at the Fort Martin and Harrison power stations.
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. On April 25, 2024, the EPA issued a final rule, which we refer to as the GHG rule, that imposed stringent GHG emissions limitations based on fuel type and unit retirement date. 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. The D.C. Circuit subsequently granted a motion from the EPA placing the litigation in abeyance until further order of the Court. On June 17, 2025, the EPA published a proposed rule to repeal the GHG rule. The EPA is expected to issue a final rule repealing all or portions of the GHG rule in February 2026.
At the state level, there are several initiatives to reduce GHG emissions. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.
FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). FirstEnergy’s ability to achieve its GHG reduction goal is subject to its ability to make operational changes and is conditioned upon numerous risks, many of which are outside of its control. With respect to FirstEnergy’s coal-fired facilities in West Virginia, which serve as the primary source of its Scope 1 emissions, it has identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. MP filed its 10-year integrated resource plan with the WVPSC on October 1, 2025, which highlighted, among other things, the need for new dispatchable generation in West Virginia. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If FirstEnergy is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s financial condition, results of operations, and cash flow. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigationallegingdamages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
FirstEnergy continues to monitor climate change policies at both the federal and state level. Based on the EPA’s final rule rescinding the 2009 Endangerment Filing and other anticipated rulemaking, we may experience a reduction in GHG reporting and other regulatory obligations at the federal level over the near term. Multiple lawsuits opposing the EPA’s rescission were filed after it was finalized and the legal conflict is expected to be extensive. In light of the pending legal challenges, FirstEnergy is unable to predict the impact on its business and operations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits were renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025, for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired electric generation facilities that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the U.S. Court of Appeals for the Fifth and Eighth Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the rule pending disposition on the merits. A number of other parties have challenged the final rule in various petitions for review across several circuits. Those petitions and motions for stay have been consolidated in the U.S. Court of Appeals for the Eighth Circuit. On October 10, 2024, the U.S. Court of Appeals for the Eighth Circuit denied the motions for stay. Depending on the outcome of appeals and the EPA’s review, compliance with the 2024 ELG rule could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. On February 19, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the U.S. Court of Appeals for the Eighth Circuit, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. On February 28, 2025, U.S. Court of Appeals for the Eighth Circuit granted the EPA’s motion. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the 2024 ELG rule. On December 31, 2025, the EPA published a final ELG Deadline Extensions Rule extending certain compliance deadlines included in the 2024 ELG Rule by five years.
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 generation facilities. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA. As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station. During 2024, as a result of the evaluation of closure options for McElroy’s Run CCR impoundment facility and the adjacent landfill, AE Supply reviewed its ARO and future expected costs to remediate, resulting in an increase to the ARO liability of $87 million. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025 with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. In connection with the transfer, AE Supply recognized a $130 million liability, based on a 4.8% weighted average discount rate over the contract term, associated with its remaining obligation to fund the escrow account over the next five years, and derecognized the ARO, resulting in an immaterial impact to earnings. During the twelve months ended December 31, 2025, AE Supply made $46 million of cash payments to the escrow account.
On May 8, 2024, the EPA issued the legacy CCR rule, which finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR
Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. On February 13, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation, which was filed on August 8, 2024, by the Utility Solid Waste Act Group with FE as a member, in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed, which the D.C. Circuit granted. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the final legacy CCR rule. FirstEnergy continues to monitor the EPA’s actions related to CCR regulations; however, the ultimate impact is unknown at this time and is subject to the outcome of the litigation and any future state regulatory actions. Depending on the outcome of appeals and the EPA’s rule, compliance with the final legacy CCR rule could require remedial actions, including removal of coal ash. See Note 9., “Asset Retirement Obligations,” of the Combined Notes to Financial Statements of the Registrants above for a description of the $139 million increase to its ARO that FirstEnergy recorded during 2024 as a result of its analysis and reduced in the fourth quarter of 2025 based on the completion of engineering studies and field analysis of certain sites. JCP&L did not have any potential legacy CCR disposal sites that were applicable to the 2024 legacy CCR rules. During the fourth quarter of 2025, FirstEnergy completed engineering studies and field analysis for certain of its legacy CCR disposal sites and determined that certain of those sites did not meet criteria to be applicable to the CCR rules. As a result, during the fourth quarter of 2025, FirstEnergy recorded a $49 million decrease to its ARO.
Certain of the FirstEnergy companies 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, 2025, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $97 million have been accrued through December 31, 2025, of which approximately $70 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 criminalallegations 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; the Sixth Circuit recently rejected their appeal upholding their convictions. 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 criminalallegations, affidavit or subpoenas before July 21, 2020. On January 17, 2025, the U.S. Attorney’s Office announced that a federal grand jury charged two former FirstEnergy senior officers with one count of participating in a Racketeer Influenced and Corrupt Organizations Act conspiracy. The allegations in the indictment are largely based on the conduct described in the DPA.
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter as to FE. Under the DPA, FE agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA required that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, consisting of (x) $115 million paid by FE to the U.S. Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of 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 an 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, criminalprosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the aforementioned federal indictmentagainst two former FirstEnergy
senior officers. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information. On February 26, 2025, the U.S. Attorney’s Office filed a status report confirming these commitments.
Legal Proceedings Relating to U.S. v. Larry Householder, et al.
Certain FE stockholders and FirstEnergy customers also filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted).
• 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 allegingviolations 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 complaintalleges, 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 allegedmisrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act as a result of allegedmisrepresentations 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 Sixth Circuit seeking to appeal that order. On August 13, 2025, the Sixth Circuit vacated the S.D. Ohio’s order granting class certification. On November 6, 2025, the S.D. Ohio held oral argument to further consider class certification in light of the Sixth Circuit’s decision. 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 complaintsagainst FE, certain current and former officers, and certain then-current and former officers of Energy Harbor Corp. The complaintsallege that the defendantsviolated Sections 10(b) and 20(a) of the Exchange Act by issuing allegedmisrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
The outcome of any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Registrants’ normal business operations pending against them or their subsidiaries. The loss or range of loss in these matters is not expected to be material to the Registrants. The other potentially material items not otherwise discussed above are described under Note 13., “Regulatory Matters” of the Combined Notes to Financial Statements of the Registrants.
The Registrants accrue legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where the Registrants determine that it is not probable, but reasonably possible that they have a material obligation, they disclose such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that the Registrants have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on the Registrants’ financial condition, results of operations, and cash flows.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Registrants prepare financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. The Registrants' 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 Combined Notes to Financial Statements of the Registrants.
Loss Contingencies
The Registrants are involved in a number of investigations, litigation, regulatory audits, arbitration, mediation, and similar proceedings. The Registrants regularly assess their liabilities and contingencies in connection with asserted or potential matters and establish reserves when appropriate. In the preparation of the financial statements, the Registrants make judgment regarding the future outcome of contingent events based on currently available information and accrue liabilities when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. In cases where the Registrants determine that it is not probable, but reasonably possible that they have a material obligation, such obligations are disclosed and the possible loss or range of loss if such estimate can be made. Circumstances change over time and actual results may vary significantly from estimates. See Note 13., “Regulatory Matters” and Note 14., “Commitments, Guarantees and Contingencies,” of the Combined Notes to Financial Statements of the Registrants for additional information.
Revenue Recognition
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants account for revenue 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
The Registrants follow 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.
The Registrants' 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.
The Registrants have elected the optional invoice practical expedient for most of their revenues and the Registrants utilize 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 Combined Notes to Financial Statements of the Registrants for additional information.
Regulatory Accounting
The Registrants are subject to regulation that sets the prices (rates) they 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.
The Registrants review 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, the Registrants 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, the Registrants will write off that regulatory asset as a charge against earnings. The Registrants consider 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 noncurrent section on the Registrants' Balance Sheets. See Note 13., "Regulatory Matters," of the Combined Notes to Financial Statements of the Registrants for additional information.
Pension and OPEB Accounting
FirstEnergy provides qualified benefit plans (the FirstEnergy Master Pension Plan and the FirstEnergy Welfare Plan) that cover substantially all employees and non-qualified defined benefit plans that cover certain employees, including employees of JCP&L.
The retirement plans provide defined benefits based on years of service and compensation levels. Under the cash balance formula of the FirstEnergy Master Pension Plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions on behalf of eligible employees based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to 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’s pension and OPEB plans are neither multiemployer nor multiple-employer plans. JCP&L recognizes its allocated portion of the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. JCP&L also recognizes its allocated portion of obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
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 OPEB 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 2026 is 8.0% and 7.0%, respectively.
Mortality Rates - The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. The Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due to the ongoing impact of COVID-19, was utilized to determine the 2026 benefit cost and obligation as of December 31, 2025, 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, net of amounts capitalized, in the years ended December 31, 2025, 2024, and 2023:
Net Periodic Benefit Costs (Credits)
(In millions)
Pension
OPEB
Total
The annual pre-tax pension and OPEB mark-to-market adjustment (gains) or losses, for the years ended December 31, 2025, 2024, and 2023, were $(253) million, $22 million and $78 million, respectively.
FirstEnergy expects its 2026 pre-tax net periodic credit, prior to amounts capitalized and excluding any potential mark-to-market adjustments, to be approximately less than $1 million based upon the following assumptions:
Assumption
Pension
OPEB
Effective rate for interest on benefit obligations
Effective rate for service costs
Effective rate for interest on service costs
Expected return on plan assets
Rate of compensation increase
The approximate effects on 2026 pension and OPEB net periodic benefit costs and the 2025 benefit obligation from changes in key assumptions are as follows:
Approximate Effect on 2026 Net Periodic Benefit Costs from Changes in Key Assumptions
Assumption
Change
Pension
OPEB
Total
(In millions)
Discount rate
Change by 0.25% (1)
Expected return on plan assets
Change by 0.25%
Health care trend rate
Change by 1.0%
(1) Assumes a parallel shift in yield curve.
Approximate Effect on December 31, 2025 Benefit Obligation from Changes in Key Assumptions
Assumption
Change
Pension
OPEB
Total
(In millions)
Discount rate
Change by 0.25% (1)
Health care trend rate
Change by 1.0%
(1) Assumes a parallel shift in yield curve.
See Note 4., "Pension and Other Postemployment Benefits," of the Combined Notes to Financial Statements of the Registrants for additional information.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes, including reserve amounts for uncertain tax positions and reporting of tax-related assets and liabilities. The Registrants are required to make judgments regarding the interpretation of tax laws and associated regulations and the potential tax effects of various transactions and results of operations in order to estimate their obligations to taxing authorities.
The Registrants record 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.
The Registrants account for uncertainty in income taxes in their 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. The Registrants recognize 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 6., "Taxes," of the Combined Notes to Financial Statements of the Registrants for additional information on income taxes.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants for a discussion of new accounting pronouncements.
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
This Form 10-K discusses JCP&L's 2025 and 2024 results and year-over-year comparisons between 2025 and 2024. Discussions of 2023 results and year-over-year comparisons between 2024 and 2023 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in JCP&L's Form S-4 filed with the SEC on April 1, 2025.
JCP&L is a wholly owned subsidiary of FE. JCP&L conducts business in New Jersey by providing regulated electric transmission and distribution services in northern, western and east central New Jersey. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU. JCP&L is subject to regulation by the NJBPU and FERC.
JCP&L's reportable operating segments are comprised of the Distribution and Transmission segments.
JCP&L's Distribution segment, representing $3.7 billion in rate base as of December 31, 2025, distributes electricity to approximately 1.2 million customers in New Jersey across its distribution footprint. The segment’s results reflect the costs of securing and delivering electric generation to customers, including the deferral and amortization of certain costs.
JCP&L's Transmission segment, representing $1.4 billion in rate base as of December 31, 2025, includes transmission infrastructure owned and operated by JCP&L that is 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 are subject to an annual true-up based on actual rate base and costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on JCP&L’s transmission facilities.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Executive Summary and Recent Developments, Regulatory Assets and Liabilities, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook, Critical Accounting Policies and Estimates and New Accounting Pronouncements.
As discussed, in Note 1.,"Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants, during the fourth quarter of 2025, JCP&L identified an error in the recording of certain expenses for smart meter cost of removal associated with the deployment of its AMI program, resulting in an understatement of expense on the Statements of Income and Comprehensive Income and Regulatory assets/liabilities on the Balance Sheets since 2023. JCP&L evaluated the error, and the specific impact on each affected prior period was not material, however, as a result of the cumulative impact, JCP&L determined it should revise previously issued financial statements to correct the error and in doing so also corrected other immaterial errors. These adjustments have been reflected in this Form 10-K for JCP&L.
JCP&L Summary of Results of Operations — 2025 Compared with 2024
Financial results for JCP&L's business segments for the years ended December 31, 2025 and 2024, were as follows:
2025 Financial Results
Reconciling
(In millions)
Distribution
Transmission
Adjustments
JCP&L
Revenues
Operating Expenses:
Purchased power
Other operating expenses
Provision for depreciation
Deferral of regulatory assets, net
General taxes
Total operating expenses
Other Income (Expense):
Miscellaneous income (expense), net
Pension and OPEB mark-to-market adjustment
Interest expense - non-affiliates
Interest expense - affiliates
Capitalized financing costs
Total other income (expense)
Income taxes
Net Income
2024 Financial Results (1)
Reconciling
(In millions)
Distribution
Transmission
Adjustments
JCP&L
Revenues
Operating Expenses:
Purchased power
Other operating expenses
Provision for depreciation
Deferral of regulatory assets, net
General taxes
Total operating expenses
Other Income (Expense):
Miscellaneous income (expense), net
Pension and OPEB mark-to-market adjustment
Interest expense - non-affiliates
Interest expense - affiliates
Capitalized financing costs
Total other expense
Income taxes
Net Income
(1) Previously issued 2024 JCP&L amounts have been revised due to the correction of immaterial errors as discussed in Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants.
Changes Between 2025 and 2024
Financial Results
Reconciling
Increase (Decrease)
Distribution
Transmission
Adjustments
JCP&L
(In millions)
Revenues
Operating Expenses:
Purchased power
Other operating expenses
Provision for depreciation
Deferral of regulatory assets, net
General taxes
Total operating expenses
Other Income (Expense):
Miscellaneous income (expense), net
Pension and OPEB mark-to-market adjustment
Interest expense - non-affiliates
Interest expense - affiliates
Capitalized financing costs
Total other income (expense)
Income taxes
Net Income
JCP&L’s Distribution Segment - 2025 compared with 2024
Net income increased $50 million in 2025, as compared to 2024 , primarily due to higher revenues from the implementation of the base rate case in February 2024, the absence of a $53 million charge in connection with the base rate case settlement agreement, as further discussed below, higher customer usage and demand, higher pension and OPEB mark-to-market adjustments and higher rider revenues associated with regulated investment programs, partially offset by higher operating expenses.
Revenues
The $329 million increase in total revenues resulted from the following sources:
For the Years Ended December 31,
Revenues by Type of Service
Increase / (Decrease)
(In millions)
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Other
Total Revenues
Distribution services revenue increased $45 million in 2025, as compared to 2024, primarily due to higher revenues from the implementation of the base rate case in February 2024, higher customer usage and demand, and higher rider revenues associated with certain regulated investment programs.
Generation sales revenues increased $288 million in 2025, as compared to 2024, primarily due to higher non-shopping generation auction rates. Retail generation sales have no material impact to earnings.
Operating Expenses
Total operating expenses increased $290 million primarily due to:
• Purchased power costs, which have no material impact to earnings, increased $247 million in 2025, as compared to 2024, primarily due to higher unit costs.
• Other operating expenses increased $46 million in 2025, as compared to 2024, primarily due to:
• Higher uncollectible expenses of $4 million, which were deferred for future recovery;
• Higher storm restoration expenses of $14 million, which were mostly deferred for future recovery.
• Higher energy efficiency and other state mandated program costs of $39 million, which were deferred for future recovery, resulting in no material impact to earnings; and
• Higher other operating expenses of $51 million, primarily due to severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025, higher employee benefit costs, and higher material and contractor spend, partially offset by increased construction support and lower maintenance work.
The increase was partially offset by:
• The absence of a $53 million pre-tax charge at JCP&L in the first quarter 2024 associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the base rate case settlement agreement, to be disallowed from future recovery; and
• The absence of a $9 million impairment related to the Akron general office in the third quarter of 2024.
• Depreciation expense increased $6 million in 2025, as compared to 2024, primarily due to a higher asset base.
• Deferral of regulatory assets, net increased $10 million in 2025, as compared to 2024, primarily due to a $27 million increase from higher deferral of storm related expenses, including the absence of the approval in the first quarter of 2024 to recover $11 million in previously incurred storm costs and a $6 million net increase in other deferrals, partially offset by a $20 million decrease due to the absence of the amortization of a regulatory liability related to customer refunds in 2024 and a $3 million net decrease from lower generation and transmission deferrals.
Other Expenses
Total other expenses decreased $30 million in 2025, as compared to 2024, primarily due to higher pension and OPEB mark-to-market adjustments, lower interest on short-term borrowings and higher capitalized interest, partially offset by long-term debt issuances since 2024.
Income Taxes
The Distribution segment's effective tax rate was 25.8% and 25.2% for 2025 and 2024, respectively.
JCP&L’s Transmission Segment - 2025 compared with 2024
Net income increased $14 million in 2025, as compared to 2024 , primarily due to higher revenues from regulated transmission investments that increased rate base, higher capitalized financing costs and the absence of a non-recoverable charge related to an abandoned transmission project in the second quarter 2024.
Revenues
Transmission revenue increased $17 million in 2025, as compared to 2024, primarily due to higher revenues from regulated transmission investments that increased rate base and higher recovery of transmission operating expenses.
Operating Expenses
Total operating expenses increased $12 million in 2025, as compared to 2024, primarily due to higher depreciation, higher operating and maintenance expenses, and higher property tax expenses from a higher asset base. Nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expenses
Total other expenses decreased $10 million in 2025, as compared to 2024, primarily due to higher capitalized financing costs and the absence of a non-recoverable charge related to an abandoned transmission project in the second quarter 2024, partially offset by higher interest expenses on new long-term debt issuances.
Income Taxes
The Transmission segment's effective tax rate was 26.1% and 28.5% for 2025 and 2024, respectively. The decrease in the effective tax rate was primarily due to an increase in the tax benefit from AFUDC equity flow-through.
