What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-18 compared with 2025-02-27 · 1010 added, 1178 removed, 805 unchanged (73% of the section changed)

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Forward-Looking Statements:

This Form 10-K includes forward-looking statements based on information currently available to management.

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.

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Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms):

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

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

• The risks and uncertainties associated with litigation, arbitration, mediation and similar proceedings, particularly regarding HB 6 related matters.

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

• Variations in weather, such as mild seasonal weather variations and severe weather conditions (including events caused, or exacerbated, by climate change, such as wildfires, hurricanes, flooding, droughts, high wind events and extreme heat events) and other natural disasters, which may result in increased storm restoration expenses and negatively affect future operating results.

• The risks and uncertainties associated with litigation, including the securities class-action lawsuit, regulatory proceedings, arbitration, mediation and similar proceedings;

• The potential liabilities and increased costs arising from regulatory actions or outcomes in response to severe weather conditions and other natural disasters;

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

• 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 meet our goals relating to climate-related and environmental, social and governance matters, opportunities, improvements, and efficiencies, including our GHG reduction goals.

• The ability to accomplish or realize anticipated benefits through establishing a culture of continuous improvement and our other strategic and financial goals, including, but not limited to, executing Energize365, our transmission and distribution investment plan, executing on our rate filing strategy, controlling costs, improving credit metrics, maintaining investment grade ratings, strengthening our balance sheet and growing earnings;

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

• Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets, including those sites impacted by the legacy CCR rules that were finalized during 2024.

• Changes to environmental laws and regulations, including, but not limited to, rules finalized by the EPA and SEC, including those currently stayed, related to climate change, and potential changes to such laws and regulations as a result of the new U.S.

presidential administration.

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

• 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;

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

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

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

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

• Changes to significant accounting policies;

• Any changes in tax laws or regulations, including, but not limited to, the IRA of 2022, or adverse tax audit results or rulings and potential changes to such laws and regulations as a result of the new U.S.

presidential administration.

• 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;

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

Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by the FE Board at the time of the actual declarations.

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 FirstEnergy's other filings with the SEC.

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.

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We expressly disclaim any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference as a result of new information, future events or otherwise.

Forward-looking and other statements in this Annual Report on Form 10-K regarding our Climate Strategy, including our GHG emission reduction goals, are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC.

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.

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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

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Distribution, Integrated and Stand-Alone Transmission.

Its electric distribution companies form one of the nation's largest investor-owned electric systems, serving over six million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York.

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.

As of December 31, 2024, AGC and MP control 3,604 MWs of net maximum generation capacity.

In addition, MP and AGC control 3,610 MWs of total generation capacity.

Segment Overview

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

FirstEnergy’s reportable segments are as follows:

The Distribution segment, which consists of the Ohio Companies and FE PA, representing $11 billion in rate base as of December 31, 2024, distributes electricity through FirstEnergy’s electric operating companies in Ohio and Pennsylvania.

The Distribution segment serves approximately 4.3 million customers in Ohio and Pennsylvania across its distribution footprint and purchases power for its provider of last resort, SOS, standard service offer and default service requirements.

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.

The Integrated segment includes the distribution and transmission operations under JCP&L, MP and PE, as well as MP’s regulated generation operations, representing $9.6 billion in rate base as of December 31, 2024.

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 3,604 MWs of regulated net maximum generation capacity located primarily in West Virginia and Virginia.

The segment will also include MP and PE’s 50 MWs of solar generation at five sites in West Virginia once complete.

The first two solar generation sites were completed and placed in service in January and September 2024, representing 24 MWs of net maximum generating capacity.

The remaining three sites, once completed, are expected to provide 26 MWs of additional net maximum generation capacity.

The Stand-Alone Transmission segment, which consists of FE's ownership in FET and KATCo, representing $5.3 billion in rate base as of December 31, 2024, includes transmission infrastructure owned and operated by the Transmission Companies and used to transmit electricity.

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.

KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains in the Stand-Alone Transmission segment.

On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and prior year results in the Stand-Alone Transmission segment reflect the earnings and results of those WP transmission assets.

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

Also included in Corporate/Other for segment reporting is 67 MWs of net maximum generation capacity, representing AE Supply’s OVEC capacity entitlement.

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.

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.

FirstEnergy believes that this segment reporting serves to provide:

• Greater transparency into our business unit performance;

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

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

• Consistency with peers.

PA Consolidation

On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, rendering FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies.

As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies.

FirstEnergy continues to evaluate the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio power company.

Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET.

So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.

FET Equity Interest Sale

On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion.

The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements.

The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with:

(i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024.

The remaining $2.3 billion of the purchase price was paid in cash at closing.

On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes.

Interest income associated with the promissory notes was $24 million for the year ended December 31, 2024 and is reported within “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income.

As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.

Asset Retirement Obligations

On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments, and in November 2024 and January 2025, the EPA made several technical corrections to the rule.

The rule extends 2015 CCR rule requirements for groundwater monitoring and protection procedures, operational and reporting procedures, as well as closure requirements for impoundments and landfills that were not originally included for coverage by the 2015 CCR rule.

In anticipation of such expenditures, FirstEnergy performed a preliminary assessment of former CCR disposal sites and calculated an initial estimate applying historical experience in remediating comparable sites.

As a result, FirstEnergy recorded a $139 million increase to its ARO during 2024, of which $113 million is included in “Other operating expenses” on the Consolidated Statements of Income and was not capitalized as an asset retirement cost since the associated plants do not have future cash flows.

On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request was withdrawn by AE Supply on July 9, 2024, prior to the completion of the technical review by the EPA.

As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station.

As of December 31, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station.

During the second quarter of 2024, as a result of the evaluation of closure options for McElroy’s Run and the adjacent landfill, AE Supply reviewed its ARO and future expected costs to remediate, resulting in an increase to the ARO liability and corresponding increase to “Other operating expense” of $87 million at Corporate/Other for segment reporting.

On February 3, 2025, AE Supply executed an environmental liability transfer agreement with a subsidiary of IDA Power, LLC, whereby AE Supply will transfer the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations.

The agreement requires AE Supply to establish a $160 million escrow account that AE Supply will fund over five years.

The escrow funding obligation will be secured by a surety bond, which will be guaranteed by FE.

The transaction is expected to close before the end of the first quarter of 2025 and the derecognition of the ARO is not expected to have a material impact to FirstEnergy’s financial statements, however, no assurances of the closing of the transfer will be satisfied, including transfer of all required environmental permits.

See Note 10, “Asset Retirement Obligations,” of the Notes to Consolidated Financial Statements.

Powered by its employees and guided by its experienced leadership team and engaged FE Board, FirstEnergy is accelerating its transformation into a premier electric company.

The FE Board and FirstEnergy’s executive management team are aligned behind a business model grounded in investing, operating, recovering costs and financing our regulated electric company operations.

This business model aims to create a “virtuous cycle” that, in turn, serves to improve reliability and the customer experience, grow rate base, engage employees, improve returns and maintain a strong balance sheet.

Along with an unwavering commitment to ethics and integrity, performance excellence and continuous improvement, FirstEnergy anticipates that strong execution of this model will help achieve its strategic objectives and deliver value to its investors.

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

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.

This includes the following:

• A robust plan for customer-focused growth, Energize365 is the centerpiece of FirstEnergy’s regulated distribution and transmission capital investment strategy that aims to strengthen the grid and enable the energy transition.

Through the Energize365 program, FirstEnergy invested $4.5 billion in 2024, approximately 20% higher than 2023, and expects to spend approximately $28 billion in system-wide capital investments from 2025 through 2029.

FirstEnergy expects that these investments will comprise the Distribution segment (26%), the Integrated segment (39%), and the Stand-Alone Transmission segment (34%), focusing on the following:

• Distribution and Transmission investments to support improvements in grid reliability and resiliency and support the energy transition, including through:

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

◦ Operational flexibility projects that are expected to build capacity and support the evolving grid such as interconnection of New Jersey offshore wind and data center load;

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;

• West Virginia solar generation projects, energy efficiency initiatives, electric vehicle infrastructure and energy storage projects.

• 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 fuel plants and remain compliant with environmental regulations through the end of their useful life.

and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

• On July 26, 2024, FE, VEPCO and Transource Energy, LLC, a subsidiary of AEP, entered into a joint proposal agreement in connection with PJM’s 2024 Regional Transmission Expansion Plan Open Window 1 process.

Pursuant to such joint proposal agreement, FET, VEPCO and Transource Energy, LLC jointly proposed certain regional electric transmission projects for PJM's consideration during the Open Window process.

On November 25, 2024, FET, Dominion High Voltage MidAtlantic, Inc., as affiliate of VEPCO, and Transource Energy, LLC, formed Valley Link, which is the holding company responsible for managing and executing any projects awarded by PJM, and entered into a limited liability agreement.

On February 26, 2025, PJM selected certain of the joint proposed projects, which included approximately $3 billion in investments for Valley Link to both build new and upgrade existing transmission infrastructure.

• A refreshed and revitalized leadership team.

During 2024, FirstEnergy appointed five executives to oversee the Maryland/West Virginia, Ohio, Pennsylvania, New Jersey and Transmission operations.

Additionally, FirstEnergy also announced the hiring of five vice presidents that will be responsible for developing and implementing the financial strategy and oversee relationships with regulators for Pennsylvania, New Jersey, West Virginia, Maryland, Ohio and Transmission.

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

It aims to do so through the following:

• Enhancing the focus on the customer.

FirstEnergy has shifted more decision-making and accountability for our operations closer to our customers, regulators and employees doing the work.

FirstEnergy’s new operating structure is organized as follows:

Ohio, Pennsylvania, New Jersey, West Virginia/Maryland and FirstEnergy’s Standalone Transmission properties.

This structure fosters better execution at the business unit level.

• Embracing a continuous improvement mindset.

FirstEnergy is focused on operational excellence through strong execution of our capital investments to enhance the customer experience and support the energy transition, managing costs and keeping customer bills affordable and reducing regulatory lag.

FirstEnergy is establishing a track record of strong execution.

Operating effectively leads to strong, predictable results and enhances credibility with our stakeholders.

In turn, FirstEnergy builds supportive relationships with regulators, customers and intervenors in an effort to drive positive rate outcomes that support recovery of its investments.

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

This includes the following:

• On March 16, 2023, JCP&L filed a base rate case in New Jersey, requesting a $185 million increase in base distribution revenues to support investments to strengthen the energy grid, enhance the customer experience and provide assistance to low-income and senior citizen customers.

On February 1, 2024, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s request for a distribution base rate increase.

The settlement, which was approved by the NJBPU on February 14, 2024, provides for an $85 million annual base distribution revenue increase for JCP&L, which became effective for customers on June 1, 2024.

• On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits.

• 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.

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 enable enhanced shareholder returns, while still allowing for continued substantial regulated investments.

Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings, 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.

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.

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.

EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years.

JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition.

• On December 1, 2023, JCP&L filed a petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and had a proposed budget of approximately $964 million.

30, 2024, the NJBPU approved the parties’ stipulation of settlement, wherein the parties agreed to a budget of approximately $817 million for EE&C Plan II, including $784 million of investments that will earn a return on equity of 9.6%, with an equity ratio of 52%, and will be recovered over 10 years.

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.

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ESP V additionally proposed new riders that would support reliability, and included provisions supporting affordability and enhancing the customer experience.

On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which are described below in “Outlook - State Regulation - Ohio”.

On 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 below in “Outlook - State Regulation - Ohio”.

• On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI, which would begin concurrently with the effective date of any new base distribution rates resulting from the Ohio Companies’ pending base rate case and continue through May 31, 2028.

ESP VI proposes to continue existing riders to support continued maintenance of the distribution system, and to reestablish riders to recover vegetation management and storm restoration expenses.

ESP VI also includes provisions supporting affordability and enhancing the customer experience.

The PUCO has scheduled a technical conference for March 12, 2025.

• On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan, which was approved by the PUCO on December 18, 2024.

The stipulation provides for the deployment of approximately 1.4 million smart meters to the balance of the Ohio Companies’ customers.

Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million.

On December 18, 2024, the PUCO approved the stipulation and implementation has since begun.

On 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.

The net increase represented a 1.5% average residential monthly bill increase.

Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual amount each year using this method.

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 to incorporate matters in the rate case as directed by the PUCO’s ESP V order.

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.

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On January 27, 2025, the Ohio Companies notified the PUCO of their intention to update their application for an increase in base distribution rates to remove ESP V related provisions from the base rate case.

The PUCO staff hired a third party auditor to assist in the review of the Ohio Companies’ base rate case filing and on February 21, 2025, PUCO staff and the third party auditor each filed their reports.

The auditor’s report recommended adjustments which would result in a net increase of the Ohio Companies’ base distribution revenues of approximately $8 million with a return on equity of 9.63% and capital structures of 48.8% debt and 51.2% equity for each of the Ohio Companies.

PUCO staff’s report takes limited positions on the auditor’s finding and recommendations and makes additional findings.

The Ohio Companies plan to respond and file supplemental testimony by March 24, 2025.

• On April 2, 2024, FE PA filed a base rate case with the PPUC seeking a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and which reflects a roll-in of several current riders such as DSIC, Tax Act, and smart meter.

Additionally, FE PA requested an enhanced ten year vegetation management program and recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others.

On September 13, 2024, FE PA and the active parties to the proceeding filed a joint settlement agreement requesting that the administrative law judges

approve FE PA’s requested distribution base rate case increase subject to the terms and conditions of the settlement, which includes, among other things, an annual net revenue increase of $225 million.

Other key components of the settlement agreement include recovery of costs incurred for storms and COVID-19, additional cost recovery of ongoing storm costs, inspection and maintenance of overhead lines and transformers, and rate case expenses, as well as an enhanced vegetation management program.

On October 15, 2024, the administrative law judges issued a decision recommending that the PPUC approve, without modification, the September 13, 2024 settlement agreement.

On November 21, 2024, the PPUC unanimously approved the settlement agreement without modification and the rates became effective on January 1, 2025.

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

FE PA’s application was approved by the PPUC on December 19, 2024, and implementation began in January 2025.

West Virginia

• On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets.

On August 22, 2023, the parties filed a unanimous settlement of the case recommending a $33 million annual increase in depreciation expense, effective April 1, 2024, but deferred issues related to a change in the net energy metering credit.

An order was issued on March 26, 2024 approving the settlement without modification.

• On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit.

Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19.

The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding.

An agreement on the net energy metering credit was subsequently submitted to the WVPSC and was materially approved as part of the base rate case order for rates effective March 27, 2024.

We believe that FirstEnergy represents a compelling investment.

With sound capital allocation targeting reliability, resiliency, the energy transition and customer experience, and supported by constructive regulatory outcomes, FirstEnergy expects to finance the business at a lower cost of capital, allowing it to begin the virtuous cycle all over again at “Invest.”

FirstEnergy aims to do this through a strengthened financial position.

Since 2021, FirstEnergy has raised $7 billion in equity capital and issued $1.5 billion in convertible notes in May 2023 to significantly improve its balance sheet.

The strength of FirstEnergy’s balance sheet supports its plan to fund Energize365 investments through organic internal cash flows and the issuance of debt rather than incremental equity.

FirstEnergy has optimized its financing plan to retain flexibility in an uncertain interest rate environment.

FirstEnergy has also taken steps to reduce potential volatility risk associated with its pension plan.

In January 2025, FirstEnergy executed an additional pension lift-out transaction associated with over $652 million in pension obligations relating to its former competitive generation employees.

FirstEnergy also expects to continue returning value to shareholders.

In March 2024, the FE Board declared a $0.015 per share increase to the quarterly common stock dividend payable June 1, 2024, to $0.425 per share, which represents an approximate 6% increase compared to dividends declared in 2023.

Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments.

Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings growth, credit metrics and other business conditions.

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

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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;

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;

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Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S.

Attorney’s Office, including the January 17, 2025, indictment against two former FirstEnergy senior officers, as described below in “Outlook -- Other Legal Proceedings - United States v.

Larry Householder, et al.”.

Attorney’s Office, including the January 17, 2025, indictment against two former FirstEnergy senior officers, as described below in “Outlook -- Other Legal Proceedings - U.S.

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 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve multiple shareholder derivative lawsuits that were filed in the S.D.

Ohio, the N.D.

Ohio, and the Ohio Court of Common Pleas, Summit County, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr.

On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D.

Ohio, which was granted on May 9, 2022.

On August 23, 2022, the S.D.

Ohio granted final approval of the settlement, which was subsequently appealed.

On February 16, 2024, the U.S.

Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval.

All appeal options were exhausted on May 16, 2024, and the judgment and settlement became final, resolving the derivative lawsuits.

On May 17, 2024, the N.D.

Ohio granted the parties’ motion to dismiss based upon the approval of the settlement by the S.D.

The state court action was also dismissed on September 2, 2022.

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

The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.

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

On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied.

FirstEnergy cooperated fully with the SEC investigation, and on September 12, 2024, the SEC issued a settlement order that concluded and resolved the investigation in its entirety.

Under the terms of the settlement, FE agreed to pay a civil penalty of $100 million and to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder, which was recognized as a loss contingency of $100 million in the second quarter of 2024 at Corporate/Other for segment reporting and paid on September 25, 2024.

On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA.

FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understood that the OOCIC’s investigation was also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr.

Householder brought in Cuyahoga County, Ohio.

FirstEnergy is cooperating with the OOCIC in its investigation.

On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the now-deceased, former chairman of the PUCO, and two former FirstEnergy senior officers, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA.

On August 12, 2024, FirstEnergy entered into a settlement with the OAG's Office, and the Summit County Prosecutor’s Office to resolve both the OOCIC investigation and State of Ohio ex rel.

Dave Yost, Ohio Attorney General v.

FirstEnergy Corp., et al.

and City of Cincinnati and City of Columbus v.

FirstEnergy Corp., noted below.

The settlement includes, among other things, a non-prosecution agreement and a payment of $19.5 million, which was recorded as a loss contingency in the second quarter of 2024 in FirstEnergy’s Consolidated Statements of Income at Corporate/Other for segment reporting and was paid on August 16, 2024.

Despite the many disruptions FirstEnergy has faced, and continues to currently face, the leadership team remains committed and focused on executing its strategy and running the business.

See “Outlook - Other Legal Proceedings” below for additional details on the government investigations, the DPA, and ongoing litigation surrounding the investigation of HB 6.

See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6.

The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FirstEnergy’s financial condition, results of operations and cash flows.

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

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Income attributable to noncontrolling interest 251 149 102 68 %

Earnings attributable to FE from continuing operations $ 978 $ 1,123 $ (145) (13) %

Earnings attributable to FE from continuing operations was $978 million or $1.70 per basic and diluted share in 2024 compared to $1,123 million or $1.96 per basic and diluted share in 2023, representing a decrease of $145 million that was primarily due to the following:

• A $200 million charge relating to an increase in ARO liabilities associated with final CCR rules and changes in future expected costs to remediate McElroy’s Run during 2024;

• A $100 million civil penalty resulting from the SEC investigation and a $19.5 million settlement with the OAG's office as further discussed below in “Outlook - Other Legal Proceedings”;

• A $62 million impairment charge related to the Akron general office in the third quarter of 2024;

• Lower revenues associated with changes to the Ohio DCR as a result of the PUCO’s ESP V order that became effective June 1, 2024;

• A $46 million charge for an expected refund, with interest, as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership, as further discussed below in "Outlook - Other Proceedings;"

• Higher non-deferred storm restoration expenses and planned vegetation management costs;

• Lower investment earnings related to FEV’s equity method investment in Global Holding, net of an impairment charge in the fourth quarter 2024;

Earnings attributable to FE $ 1,020 $ 978 $ 42 4 %

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);

• 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;

• Higher non-recoverable charges associated with regulatory proceedings and abandoned transmission projects;

• Higher debt redemption costs;

• Higher interest expense on long-term debt and short-term borrowings, partially offset by the redemption of certain FE long-term debt and higher capitalized financing costs;

• A higher effective tax rate due to tax charges related to the PA Consolidation and FET Equity Interest Sale in 2024, and the absence of a reduction in state income taxes and release of a valuation allowance recognized in 2023, partially offset by discrete tax benefits in 2024 associated with certain equity method investments and the remeasurement of excess deferred income taxes.

These were partially offset by the following:

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

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

• Higher weather-related customer usage and demand;

• Increased earnings as a result of regulated investment programs that increased rate base;

• Higher interest income on the FET Equity Interest Sale promissory notes;

• Lower Pension and OPEB mark-to-market adjustment charges;

• The absence of expenses associated with the cancellation of sponsorship agreements in 2023;

• Lower labor and benefits expenses, including those associated with the PEER program and separation-related costs.

Detailed segment reporting explanations are included below.

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

For the Years Ended December 31,

(In thousands) Actual Weather-Adjusted

Electric Distribution MWh Deliveries (1)

2024 2023 Increase 2024 2023 Increase (Decrease)

Residential 54,631 52,217 4.6 % 55,447 55,909 (0.8) %

Commercial (2)

39,021 38,179 2.2 % 39,298 39,468 (0.4) %

Industrial 52,950 52,252 1.3 % 52,951 52,252 1.3 %

Total Electric Distribution MWh Deliveries 146,602 142,648 2.8 % 147,696 147,629 — %

(1) Reflects the reclassification of certain Pennsylvania customers from Industrial to Commercial.

Due to the January 2024 consolidation of the Pennsylvania Companies, certain customers are classified as Commercial effective June 1, 2024.

The MWh deliveries prior to the effective date have been adjusted for comparability.

(2) Includes street lighting.

Residential and commercial distribution deliveries were impacted by higher customer usage as a result of the weather.

Cooling degree days in 2024 were 37% above 2023 and 15% above normal.

Heating degree days in 2024 were 1% below 2023 and 15% below normal.

The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments.

A reconciliation of segment financial results is provided in Note 16, “Segment Information,” of the Notes to Consolidated Financial Statements.

FIRSTENERGY'S CONSOLIDATED RESULTS OF OPERATIONS

2023 Compared with 2022

(In millions) For the Years Ended December 31,

2023 2022 Increase (Decrease)

Revenues 12,870 12,459 $ 411 3 %

Operating expenses (10,604) (10,549) 55 1 %

Other expenses, net (802) (471) 331 70 %

Income taxes (267) (1,000) (733) (73) %

Income attributable to noncontrolling interest (74) (33) 41 124 %

Earnings attributable to FE from continuing operations $ 1,123 $ 406 $ 717 177 %

Earnings attributable to FE from continuing operations was $1,123 million or $1.96 per basic and diluted share in 2023 compared to $406 million or $0.71 per basic and diluted share in 2022, representing an increase of $717 million that was primarily due to the following:

• The absence of an income tax charge of $752 million in 2022, representing the deferred tax liability associated with the deferred tax gain on the 19.9% FET equity interest sale to Brookfield, and a 2023 tax benefit of $65 million, net of a reserve for uncertain tax positions, from the reduction of state income taxes and partial release of a valuation allowance for the expected utilization of state NOL carryforwards based on an assessment of regulated business operations and a change in the composition of a state tax return filing group, partially offset by a $58 million tax charge in 2023 associated with a true-up adjustment associated with the deferred tax gain on the 19.9% FET equity interest sale that closed in May 2022;

• Higher revenues from regulated investment programs, higher weather-adjusted customer usage and demand, the absence of a reserve for customer refunds associated with the FERC Audit, as further discussed below, and a true-up adjustment for the recovery of certain transmission formula rate operating costs during 2023;

• Lower other operating expenses from lower vegetation management expenses, including accelerated work during 2022, fewer regulated generation planned outages, and the absence of a reserve for customer refunds and the reclassification of certain transmission capital assets that are not expected to be recoverable resulting from the FERC Audit that was recognized in the third quarter of 2022;

• Lower debt redemption costs.

These were partially offset by the following:

• Lower customer usage as a result of the weather;

• Higher other operating expenses from lump sum compensation and severance benefits associated with the PEER program and involuntary separations in 2023, and higher investigation and other related costs associated with the government investigations;

• Higher depreciation expense from a higher asset base;

• Higher pension and OPEB mark-to-market adjustment charges;

• Higher interest expense on short-term borrowings and long-term debt, including the 2026 Convertible Notes issuance;

• Higher non-recoverable charges related to abandoned transmission projects in 2023;

• The dilutive effect from the 19.9% FET equity interest sale that closed in May 2022.

• Lower customer credits associated with the PUCO-approved Ohio Stipulation.

Detailed segment reporting explanations are included below.

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Electric Distribution MWh Deliveries (1)

2023 2022 Increase (Decrease) 2023 2022 Increase

2025 2024 Increase (Decrease) 2025 2024 Increase (Decrease)

Residential 56,397 54,631 3.2 % 55,520 55,447 0.1 %

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(2) Includes street lighting.

Residential and commercial distribution deliveries were impacted by lower customer usage as a result of the weather.

Cooling degree days in 2023 were 23% below 2022 and 15% below normal.

Heating degree days in 2023 were 14% below 2022 and 15% below normal.

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 16, “Segment Information,” of the Notes to Consolidated Financial Statements.

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

13 unchanged sentences

General taxes 849 143 303 50 1,345

Ohio settlement charges 275 — — — 275

Impairment of assets 352 — — — 352

Total Operating Expenses 6,965 4,866 1,006 47 12,884

1 unchanged sentence

Debt redemption costs — — — (24) (24)

Equity method investment earnings, net — — — 58 58

Miscellaneous income, net 124 54 18 (7) 189

Miscellaneous income (expense), net 100 80 20 (44) 156

Pension and OPEB mark-to-market adjustments 125 98 23 7 253

4 unchanged sentences

Income attributable to noncontrolling interest — — 251 — 251

Earnings (Loss) Attributable to FE from Continuing Operations $ 624 $ 535 $ 294 $ (475) $ 978

Earnings (Losses) Attributable to FE $ 363 $ 588 $ 357 $ (288) $ 1,020

2024 Financial Results

11 unchanged sentences

General taxes 752 140 279 41 1,212

Impairment of assets 30 70 12 3 115

Total Operating Expenses 5,856 4,053 980 208 11,097

9 unchanged sentences

Income attributable to noncontrolling interest — — 149 — 149

Earnings (Losses) Attributable to FirstEnergy Corp.

from Continuing Operations $ 587 $ 300 $ 399 $ (163) $ 1,123

Earnings (Losses) Attributable to FE $ 624 $ 535 $ 294 $ (475) $ 978

Changes Between 2025 and 2024

Financial Results

Increase (Decrease) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated

Increase (Decrease)

Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated

(In millions)

9 unchanged sentences

General taxes 97 3 24 9 133

Ohio settlement charges 275 — — — 275

Impairment of assets 322 (70) (12) (3) 237

Total Operating Expenses 1,109 813 26 (161) 1,787

9 unchanged sentences

Income attributable to noncontrolling interest — — 102 — 102

Earnings (Loss) Attributable to FE from Continuing Operations $ 37 $ 235 $ (105) $ (312) $ (145)

Earnings (Losses) Attributable to FE $ (261) $ 53 $ 63 $ 187 $ 42

Distribution Segment — 2025 Compared with 2024

Distribution segment's earnings attributable to FE from continuing operations increased $37 million in 2024, as compared to 2023, primarily due to higher customer usage as a result of the weather, lower Ohio customer rate credits and lower Pension and OPEB mark-to-market adjustment charges, partially offset by lower weather-adjusted customer usage and demand, lower revenues due to changes in the Ohio DCR that became effective June 1, 2024, and higher operating expenses, including increases in the ARO liability.

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.

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 2024 2023 Increase (Decrease)

Revenues by Type of Service 2025 2024 Increase

(In millions)

6 unchanged sentences

Total Revenues $ 7,547 $ 6,863 $ 684

Distribution services revenues increased $333 million in 2024, as compared to 2023, primarily due to higher customer usage as a result of the weather, higher rider revenues associated with a Pennsylvania regulated investment program, and lower customer credits associated with the PUCO-approved Ohio Stipulation.

Additionally, revenues increased due to the higher recovery of transmission expenses, and other FE PA rider rate adjustments, which have no material impact to earnings.

Higher distribution services revenues were partially offset by lower weather-adjusted customer usage and demand, and lower revenues associated with changes to the Ohio DCR as a result of the PUCO’s ESP V order that became effective June 1, 2024.

Generation sales revenues decreased $320 million in 2024, as compared to 2023, primarily due to lower retail generation sales as a result of increased customer shopping, partially offset by higher non-shopping generation auction rates.

Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA in 2024, as compared to 2023, increased to 90% from 77% in Ohio and increased to 63% from 62% in Pennsylvania.

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.

1 unchanged sentence

Total operating expenses increased $1,109 million, primarily due to the following:

• Purchased power costs, which have no material impact to earnings, decreased $359 million in 2024, as compared to 2023, primarily due to lower generation sales volumes, as described above, and decreased capacity expenses, partially offset by higher unit costs.

• 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;

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

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

• $31 million impairment charge related to the Akron general office in the third quarter of 2024;

• Higher planned vegetation management expenses of $57 million;

• Higher energy efficiency and other state mandated program costs of $8 million, which were deferred for future recovery;

• Higher storm restoration expenses of $48 million, of which $38 million were deferred for future recovery;

• Higher uncollectible expenses of $40 million, of which $14 million were deferred for future recovery, primarily due to a reduction to the allowance during 2023.

• 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;

• 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:

• Lower other operating expenses of $138 million, primarily due to lower labor and benefits expenses, including those associated with the PEER program and separation-related costs.

• 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;

• 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 $88 million in 2024, as compared to 2023, primarily due to a $17 million decrease of certain Tax Act savings deferrals to FE PA customers, $69 million decrease from lower net generation and transmission related deferrals, and $40 million related to net decreases in other deferrals, partially offset by $38 million increase due to higher deferral of storm related expenses.

• General taxes increased $18 million in 2024, as compared to 2023, primarily due to higher gross receipts taxes.

• 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 $70 million in 2024, as compared to 2023, primarily due to $69 million in lower pension and OPEB mark-to-market adjustment charges.

Distribution segment's effective tax rate was 17.8% and 20.0% for 2024 and 2023, respectively, primarily due to the remeasurement of excess deferred income taxes in 2024.

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 from continuing operations increased $235 million in 2024, as compared to 2023, primarily from the implementation of base rate cases, higher customer usage and demand, higher revenues from regulated investment programs, and lower Pension and OPEB mark-to-market adjustment charges, partially offset by higher operating expenses, including increases in the ARO liability, and a higher effective tax rate discussed below.

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.

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 2024 2023 Increase (Decrease)

Revenues by Type of Service 2025 2024 Increase

(In millions)

Distribution services $ 1,698 $ 1,600 $ 98

$ 1,600 $ 1,411 $ 189

Generation sales:

8 unchanged sentences

Total Revenues $ 5,683 $ 4,876 $ 807

(1) Includes $10 million of ARP revenues in 2024, related to lost distribution revenues associated with energy efficiency in New Jersey.

Distribution services revenues increased $189 million in 2024, as compared to 2023, primarily due to higher revenues from the implementation of base rate cases, higher customer usage as a result of the weather, higher weather-adjusted customer usage and demand, and higher rider revenues associated with certain regulated investment programs.

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 $303 million in 2024, as compared to 2023, primarily due to higher retail revenues, partially offset by lower wholesale revenues.

• Retail generation sales increased $365 million in 2024, as compared to 2023, primarily due to higher customer usage as a result of the weather and higher non-shopping generation auction rates.

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 decreased $62 million in 2024, as compared to 2023, primarily due to lower capacity revenues and lower market prices, partially offset by higher sales volumes.

• 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 $62 million in 2024, as compared to 2023, primarily due to higher rate base from regulated investment programs.

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 $269 million, primarily due to:

• Fuel costs decreased $74 million in 2024, as compared to 2023, primarily due to lower unit costs and consumption volumes.

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 $161 million in 2024, as compared to 2023, primarily due to higher unit costs and volumes, partially offset by lower capacity expenses.

• 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:

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

• Higher storm restoration expenses of $80 million, of which $63 million was deferred for future recovery;

• Higher network transmission expenses of $50 million, which were deferred for future recovery, resulting in no material impact to earnings;

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

• $17 million impairment charge related to the Akron general office in the third quarter of 2024;

• Higher planned vegetation management costs of $15 million, of which $8 million were deferred for future recovery;

• Higher uncollectible expenses of $17 million, which were mostly deferred for future recovery, primarily due to a reduction to the allowance during 2023;

• 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;

• Higher storm restoration expenses of $22 million, which were mostly deferred for future recovery.

This increase was partially offset by:

• Lower other operating and maintenance expenses of $99 million, primarily due to lower labor and benefit expenses, including those associated with the PEER program and separation-related costs and lower regulated generation costs.

• 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 increased $56 million in 2024, as compared to 2023, primarily due to:

• $63 million due to higher deferral of storm related expenses;

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

• $31 million related to net increases in other deferrals;

• $12 million due to higher energy efficiency related deferrals.

This increase was partially offset by:

• $98 million due to lower net generation and transmission related deferrals;

• $12 million due to higher vegetation management program-related amortizations.

• General taxes increased $11 million in 2024, as compared to 2023, primarily due to higher gross receipts taxes.

• 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;

• 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 $64 million in 2024, as compared to 2023, primarily due to $76 million in lower pension and OPEB mark-to-market adjustment charges, higher interest expense on short-term borrowings and higher non-recoverable charges related to abandoned transmission projects, partially offset by higher capitalized interest.

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 is primarily due to the absence of discrete tax benefits related to the expected utilization of state NOL carryforwards and the release of an uncertain tax position related to state taxes recognized in 2023, partially offset by a remeasurement of excess deferred income taxes in 2024.

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 from continuing operations decreased $105 million in 2024, as compared to 2023, primarily due to the dilutive effect of the FET Equity Interest Sale that closed in March 2024, and a charge for an expected refund, with interest, as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership, partially offset by higher revenues from regulated capital investments that increased rate base.

Total revenues increased $39 million in 2024, as compared to 2023, primarily due to higher rate base and recovery of higher transmission operating expenses partially offset by a charge for an expected refund as a result of the Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership.

Revenues by transmission asset owner are shown in the following table:

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.

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,

8 unchanged sentences

Operating Expenses —

Total operating expenses increased $73 million in 2024, as compared to 2023, primarily due to higher operation and maintenance costs, higher property taxes and depreciation due to a higher asset base and a $11 million charge from FESC in connection with its planned exit from the Akron general office.

Other than the general office charge, nearly all operating expenses are recovered through formula rates, resulting in no material impact to earnings.

Other Expense —

Total other expense decreased $31 million in 2024, as compared to 2023, primarily due to lower pension and OPEB mark-to-market adjustment charges of $38 million, partially offset by higher net financing costs associated with new debt issuances and interest related to the expected refund associated with the Sixth Circuit ruling noted above.

Income Taxes —

Stand-Alone Transmission's effective tax rate was 28.1% and 23.6% for 2024 and 2023, respectively.

The increase in the effective tax rate was primarily due to discrete tax charges related to the FET Equity Interest Sale in 2024, as well as the absence of a discrete tax benefit related to the expected utilization of state NOL carryforwards recognized in 2023.

Corporate/Other — 2024 Compared with 2023

Financial results from Corporate/Other resulted in a $312 million increase in losses attributable to FE from continuing operations for 2024 compared to 2023, primarily due to:

• $120 million related to a civil penalty with the SEC and a settlement with the OAG's office as further discussed below in “Outlook - Other Legal Proceedings”;

• $111 million (after-tax) charge related to changes in ARO liabilities associated with final CCR rules and future expected costs to remediate McElroy’s Run;

• $99 million (after-tax) from higher pension and OPEB mark-to-market adjustment charges;

• $80 million (after-tax) in lower investment earnings related to FEV’s equity method investment in Global Holding;

• $38 million (after-tax) of higher debt redemption costs;

• $10 million (after-tax) related to an impairment charge recognized in the fourth quarter of 2024 associated with FirstEnergy's actions to exit FEV's equity method investment in Global Holding;

• $9 million (after-tax) of higher investigation and other related costs associated with the government investigations;

• Lower income tax benefits in 2024 as a result of tax charges related to the PA Consolidation and FET Equity Interest Sale, the absence of a reduction in state income taxes and release of valuation allowances recognized in 2023, partially offset by discrete tax benefits recognized in 2024 associated with certain equity method investments.

The increase in losses were partially offset by:

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

• $23 million (after-tax) of lower other operating expenses primarily related to the absence of expenses associated with the cancellation of certain sponsorship agreements in 2023;

• $19 million (after-tax) of higher interest income on the FET Equity Interest Sale promissory notes;

• $16 million (after-tax) of lower interest expense as a result of the redemption of certain FE long-term debt and lower short-term borrowings.

Summary of Segment Results of Operations — 2023 Compared with 2022

Financial results for FirstEnergy’s business segments for the years ended December 31, 2023 and 2022, were as follows:

2023 Financial Results

(In millions)

Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated

Electric $ 6,690 $ 4,261 $ 1,731 $ 11 $ 12,693

Other 164 59 17 (63) 177

Total Revenues 6,854 4,320 1,748 (52) 12,870

Operating Expenses:

Fuel — 538 — — 538

Purchased power 2,578 1,509 — 21 4,108

Other operating expenses 2,129 1,156 338 (29) 3,594

Provision for depreciation 620 462 304 75 1,461

Amortization (deferral) of regulatory assets, net (259) (10) 8 — (261)

General taxes 734 129 257 44 1,164

Total Operating Expenses 5,802 3,784 907 111 10,604

Other Income (Expense):

Debt redemption costs — — — (36) (36)

Equity method investment earnings, net — — — 175 175

Miscellaneous income (expense), net 84 73 17 (10) 164

Pension and OPEB mark-to-market adjustments (33) (50) (32) 37 (78)

Interest expense (390) (257) (245) (232) (1,124)

Capitalized financing costs 21 35 38 3 97

Total Other Expense (318) (199) (222) (63) (802)

Income taxes (benefits) 147 37 146 (63) 267

Income attributable to noncontrolling interest — — 74 — 74

Earnings (Loss) Attributable to FE from Continuing Operations $ 587 $ 300 $ 399 $ (163) $ 1,123

2022 Financial Results

(In millions)

Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated

Electric $ 6,267 $ 4,425 $ 1,581 $ 27 $ 12,300

Other 158 45 16 (60) 159

Total Revenues 6,425 4,470 1,597 (33) 12,459

Operating Expenses:

Fuel — 730 — — 730

Purchased power 2,236 1,606 — 21 3,863

Other operating expenses 2,094 1,226 428 69 3,817

Provision for depreciation 593 430 277 75 1,375

Amortization (deferral) of regulatory assets, net (241) (128) 4 — (365)

General taxes 714 123 247 45 1,129

Total Operating Expenses 5,396 3,987 956 210 10,549

Other Income (Expense):

Debt redemption costs — — — (171) (171)

Equity method investment earnings, net — — — 168 168

Miscellaneous income, net 165 102 55 93 415

Pension and OPEB mark-to-market adjustments (12) (43) (10) 137 72

Interest expense (325) (225) (263) (226) (1,039)

Capitalized financing costs 19 28 36 1 84

Total Other Income (Expense) (153) (138) (182) 2 (471)

Income taxes 202 80 111 607 1,000

Income attributable to noncontrolling interest — — 33 — 33

Earnings (Losses) Attributable to FirstEnergy Corp.

from Continuing Operations $ 674 $ 265 $ 315 $ (848) $ 406

Changes Between 2023 and 2022

Financial Results

Increase (Decrease) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated

(In millions)

Electric $ 423 $ (164) $ 150 $ (16) $ 393

Other 6 14 1 (3) 18

Total Revenues 429 (150) 151 (19) 411

Operating Expenses:

Fuel — (192) — — (192)

Purchased power 342 (97) — — 245

Other operating expenses 35 (70) (90) (98) (223)

Provision for depreciation 27 32 27 — 86

Amortization (deferral) of regulatory assets, net (18) 118 4 — 104

General taxes 20 6 10 (1) 35

Total Operating Expenses 406 (203) (49) (99) 55

Other Income (Expense):

Debt redemption costs — — — 135 135

Equity method investment earnings, net — — — 7 7

Miscellaneous income (expense), net (81) (29) (38) (103) (251)

Pension and OPEB mark-to-market adjustments (21) (7) (22) (100) (150)

Interest expense (65) (32) 18 (6) (85)

Capitalized financing costs 2 7 2 2 13

Total Other Income (Expense) (165) (61) (40) (65) (331)

Income taxes (benefits) (55) (43) 35 (670) (733)

Income attributable to noncontrolling interest — — 41 — 41

Earnings (Loss) Attributable to FE from Continuing Operations $ (87) $ 35 $ 84 $ 685 $ 717

Distribution Segment — 2023 Compared with 2022

Distribution segment's earnings attributable to FE from continuing operations decreased $87 million in 2023, as compared to 2022, primarily due to lower customer usage as a result of the weather, lower net pension and OPEB credits, and higher interest expense and costs from the PEER, partially offset by lower other operating expenses, higher revenues from regulated investment programs and higher weather-adjusted customer usage and demand.

Distribution's total revenue increased $429 million from the following sources:

For the Years Ended December 31,

Revenues by Type of Service 2023 2022 Increase

(In millions)

Distribution services $ 3,847 $ 3,689 $ 158

Generation sales:

Retail 2,823 2,559 264

Wholesale 20 19 1

Total generation sales 2,843 2,578 265

Other 164 158 6

Total Revenues $ 6,854 $ 6,425 $ 429

Distribution services revenues increased $158 million in 2023, as compared to 2022, primarily due to higher weather-adjusted customer usage and demand, higher rider revenues associated with a Pennsylvania regulated investment program, and lower customer credits associated with the PUCO-approved Ohio Stipulation.

Higher distribution services revenues were partially offset by lower customer usage as a result of the weather and lower recovery of transmission expenses, which have no material impact to earnings.

Generation sales revenues increased $265 million in 2023, as compared to 2022, primarily due to higher retail generation sales as a result of higher non-shopping generation auction rates, partially offset by lower customer usage as a result of the weather and increased customer shopping in Pennsylvania.

Total generation provided by alternative suppliers as a percentage of total MWh deliveries in Pennsylvania increased to 62% in 2023 as compared to 60% in 2022.

Retail and wholesale generation sales revenue have no material impact to earnings.

Operating Expenses —

Total operating expenses increased $406 million primarily due to the following:

• Purchased power costs, which have no material impact to earnings, increased $342 million in 2023, as compared to 2022, primarily due to higher volumes, partially offset by lower unit costs and capacity expenses.

• Other operating expenses increased $35 million in 2023, as compared to 2022, primarily due to:

• Lump sum compensation and severance benefits of $24 million associated with the PEER program and involuntary separations in 2023;

• Higher energy efficiency and other state mandated program costs of $26 million, which were deferred for future recovery;

• Higher storm restoration expenses of $95 million, which were mostly deferred for future recovery, resulting in no material impact to earnings recovery;

This increase was partially offset by:

• Lower vegetation management expenses of $72 million, including accelerated work during 2022;

• Lower network transmission expenses of $11 million, which are deferred for future recovery, resulting in no material impact to earnings;

• Lower uncollectible expenses of $27 million, of which $4 million was deferred for future recovery.

• Depreciation expense increased $27 million in 2023, as compared to 2022, primarily due to a higher asset base.

• Deferral of regulatory assets increased $18 million in 2023, as compared to 2022, primarily due to:

• $83 million net increase due to higher generation and transmission related deferrals;

• $98 million increase due to higher deferral of storm related expenses;

This increase was partially offset by:

• $100 million decrease due to the absence of a return of certain Tax Act savings to Pennsylvania customers in 2022;

• $51 million decrease due to the absence of the customer refunds associated with the Ohio Stipulation;

• $12 million net decreases in other deferrals.

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

Other Expense —

Other expense increased $165 million in 2023, as compared to 2023, primarily due to lower net pension and OPEB non-service credits, a $21 million change in pension and OPEB mark-to-market adjustment charges, higher net interest expense associated with new long-term issuances and higher short-term borrowings, and a charge from an environmental agreement requiring a $10 million contribution to the EPA associated with a former generation plant of OE.

Distribution segment's effective tax rate was 20.0% and 23.1% for 2023 and 2022, respectively.

Integrated Segment — 2023 Compared with 2022

Integrated segment’s earnings attributable to FE from continuing operations increased $35 million in 2023, as compared to 2022, primarily due to lower other operating expenses, higher revenues from regulated investment programs and higher weather-adjusted customer usage and demand, partially offset by lower customer usage as a result of the weather, lower net pension and OPEB credits, and higher interest expense and costs from the PEER.

Integrated segment’s total revenues decreased $150 million as a result of the following sources:

For the Years Ended December 31,

Revenues by Type of Service 2023 2022 Increase (Decrease)

(In millions)

Distribution services $ 1,411 $ 1,459 $ (48)

Generation sales:

Retail 2,324 2,209 115

Wholesale 208 475 (267)

Total generation sales 2,532 2,684 (152)

Transmission revenues:

JCP&L 206 203 3

MP & PE 112 79 33

Total transmission revenues 318 282 36

Other 59 45 14

Total Revenues $ 4,320 $ 4,470 $ (150)

Distribution services revenues decreased $48 million in 2023, as compared to 2022, primarily due to lower customer usage as a result of the weather and lower recovery of transmission expenses, partially offset by higher rider revenues associated with certain investment programs, and higher weather-adjusted customer usage and demand.

Generation sales revenues decreased $152 million in 2023, as compared to 2022, primarily due to lower wholesale revenues, partially offset by higher retail revenues.

• Retail generation sales increased $115 million in 2023, as compared to 2022, primarily due to higher non-shopping generation auction rates, partially offset by lower sales volumes.

Retail generation sales, other than those in West Virginia, have no material impact to earnings.

• Wholesale generation revenues decreased $267 million in 2023, as compared to 2022, primarily due to lower capacity revenues, market prices and sales volumes.

The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.

Transmission revenues increased $36 million in 2023, as compared to 2022, primarily due to higher rate base from regulated investment programs.

Operating Expenses —

Total operating expenses decreased $203 million, primarily due to:

• Fuel costs decreased $192 million in 2023, as compared to 2022, primarily due to lower unit costs and consumption volumes.

Due to the ENEC, fuel expense has no material impact to earnings.

• Purchased power costs, which have no material impact to earnings, decreased $97 million in 2023, as compared to 2022, primarily due to lower unit costs and capacity expenses, partially offset by higher volumes.

• Other operating expenses decreased $70 million in 2023, as compared to 2022, primarily due to:

• Lower network transmission expenses of $30 million, which are deferred for future recovery, resulting in no material impact to earnings;

• Lower uncollectible expenses of $19 million, which are deferred for future recovery, resulting in no material impact to earnings;

• Lower storm restoration expenses of $10 million, which were mostly deferred for future recovery, resulting in no material impact to earnings;

• Lower expenses of $60 million, primarily due to the absence of the reclassification of certain transmission capital assets to operating expenses as a result of the FERC Audit.

This decrease was partially offset by:

• Lump sum compensation and severance benefits of $18 million associated with the PEER program and involuntary separations in 2023;

• Higher vegetation management in West Virginia, energy efficiency and other state mandated program costs of $17 million, which were deferred for future recovery;

• Higher other operating expenses of $14 million, primarily due to higher contractor expenses, partially offset by fewer regulated generation planned outages.

• Depreciation expense increased $32 million in 2023, as compared to 2022, primarily due to a higher asset base.

• Deferral of regulatory assets decreased $118 million in 2023, as compared to 2022, primarily due to:

• $181 million net decrease due to lower generation and transmission related deferrals;

• $8 million decrease due to lower deferral of storm related expenses.

This decrease was partially offset by:

• $40 million increase due to lower vegetation management and other program-related amortizations;

• $15 million increase due to higher energy efficiency related deferrals;

• $16 million related to net increases in other deferrals.

• General taxes increased $6 million in 2023, as compared to 2022, primarily due to higher payroll taxes.

Other Expense —

Other expense increased $61 million in 2023, as compared to 2022, primarily due to lower net pension and OPEB non-service credits, a $7 million change in pension and OPEB mark-to-market adjustment charges, and higher net interest expense associated with new long-term issuances and higher short-term borrowings.

Income Taxes —

Integrated segment’s effective tax rate was 11.0% and 23.2% in 2023 and 2022, respectively.

The decrease in the effective tax rate is primarily due to discrete tax benefits related to the expected utilization of state NOL carryforwards and the release of an uncertain tax position related to state taxes recognized in 2023.

Stand-Alone Transmission Segment — 2023 Compared with 2022

Stand-Alone Transmission's earnings attributable to FE from continuing operations increased $84 million in 2023, as compared to 2022, primarily due to the absence of a reserve for customer refunds and the reclassification of certain transmission capital assets that are not expected to be recoverable resulting from the FERC Audit that was recognized in the third quarter of 2022, as further discussed below and as a result of regulated capital investments that increased rate base, partially offset by the dilutive effect of the 19.9% sale of FET equity interest that closed in May 2022.

Total revenues increased $151 million in 2023, as compared to 2022, primarily due to the absence of a reserve for customer refunds associated with the FERC Audit, as further discussed below, a true-up adjustment for the recovery of certain transmission formula rate operating costs during 2023 and a higher rate base.

Revenues by transmission asset owner are shown in the following table:

For the Years Ended December 31,

Revenues by Transmission Asset Owner 2023 2022 Increase

(In millions)

ATSI $ 974 $ 918 $ 56

TrAIL 284 275 9

MAIT 399 344 55

KATCo 89 59 30

Total Revenues $ 1,748 $ 1,597 $ 151

Operating Expenses —

Total operating expenses decreased $49 million in 2023, as compared to 2022, primarily due to the absence of the reclassification of certain transmission capital assets to operating expenses as a result of the FERC Audit, as further discussed below, partially offset by higher depreciation and property tax expenses from a higher asset base.

Other than the write-off of nonrecoverable transmission assets, nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.

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 $40 million in 2023, as compared to 2022, primarily due to a change in pension and OPEB mark-to-market adjustment charges of $22 million and pension and OPEB non-service credits partially offset by lower interest on long-term debt and borrowings under the revolving credit facilities and higher unregulated money pool interest income at FET.

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 $685 million decrease in losses attributable to FE from continuing operations for 2023 compared to 2022, primarily due to:

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

interest sale;

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;

$47 million (after-tax) of lower debt redemption costs.

• $6 million (after-tax) related to higher investment earnings on corporate-owned life insurance policies;

• $6 million (after-tax) in higher investment earnings related to FEV’s equity method investment in Global Holding.

The decrease in losses were partially offset by:

• $78 million (after-tax) related to lower pension and OPEB mark-to-market adjustment charges;

• $23 million (after-tax) of higher other operating expenses primarily related to the expenses associated with the cancellation of certain sponsorship agreements in 2023;

• $20 million (after-tax) from lower pension and OPEB non-service credits;

• $16 million (after-tax) of higher investigation and other related costs associated with the government investigations;

• $8 million (after-tax) for a charge associated with an update to the McElroy’s Run ARO;

• $5 million (after-tax) of higher interest expense from the 2026 Convertible Notes issuance.

• 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;

• 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

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Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred.

FirstEnergy, the Electric Companies and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.

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.

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Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets and liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2024 and 2023, and the changes during the year 2024:

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 2024 2023 Change

Net Regulatory Assets (Liabilities) by Source - FirstEnergy 2025 2024 Change

(In millions)

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Vegetation management costs 153 125 28

Ohio settlement charges (250) — (250)

Other 41 75 (34)

Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (378) $ (845) $ 467

Net Regulatory Liabilities included on FirstEnergy Consolidated Balance Sheets $ (356) $ (378) $ 22

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 2025 2024 Change

(In millions)

Customer payables for future income taxes $ (393) $ (410) $ 17

Spent nuclear fuel disposal costs (76) (72) (4)

Asset removal costs (1)

(87) (101) 14

Deferred transmission costs (25) (3) (22)

Deferred distribution costs 318 206 112

Storm-related costs 367 310 57

Energy efficiency program costs 316 208 108

New Jersey societal benefit costs 80 87 (7)

Other 15 22 (7)

Net Regulatory Assets included on JCP&L's Balance Sheets $ 515 $ 247 $ 268

(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 property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to federal and state tax rate changes such as the Tax Act and Pennsylvania House Bill 1342.

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 generating facilities, Oyster Creek and Three Mile Island Unit 1.

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, including amounts at December 31, 2023, expected to be refunded to, or recoverable from, wholesale transmission customers resulting from the FERC Audit, which amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.

Deferred transmission costs - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed.

Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.

Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE.

MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC.

Generally, the ENEC rate is updated annually.

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

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 $402 million and $254 million are currently being recovered through rates as of December 31, 2024 and 2023, respectively.

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.

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

The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2024 and 2023, of which approximately $698 million and $371 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:

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 2024 2023 Change

Current Return - FirstEnergy 2025 2024 Change

(In millions)

Deferred transmission costs $ 8 $ 6 $ 2

Deferred generation costs $ 280 $ 314 $ (34)

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Storm-related costs 844 694 150

Vegetation management 16 21 (5)

Other 102 82 20

Regulatory Assets Not Earning a Current Return $ 1,243 $ 1,197 $ 46

FirstEnergy's Regulatory Assets Not Earning a Current Return $ 1,425 $ 1,243 $ 182

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 2025 2024 Change

(In millions)

Deferred distribution costs $ 147 $ 101 $ 46

Storm-related costs 367 310 57

Other 24 28 (4)

JCP&L's Regulatory Assets Not Earning a Current Return $ 538 $ 439 $ 99

CAPITAL RESOURCES AND LIQUIDITY

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

FE and its subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations.

In addition to internal sources to fund liquidity and capital requirements for 2025 and beyond, FE and its subsidiaries expect to rely on external sources of funds.

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 FE and certain of its subsidiaries to, among other things, fund capital expenditures and other capital-like investments, and

refinance short-term and maturing long-term debt, subject to market conditions and other factors.

FE may utilize instruments other than senior notes to fund its liquidity and capital requirements, including hybrid securities.

Capital investments by business segment are included below:

Business Segment 2022 Actual

(In millions)

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

Distribution $ 1,020 $ 1,285 $ 1,620

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Corporate/Other 118 97 90

Total $ 3,244 $ 3,747 $ 4,499

Total - FirstEnergy $ 3,747 $ 4,499 $ 5,556

(1) Includes capital expenditures and capital-like investments that earn a return.

Capital investment forecasts for the years ended 2025, 2026, 2027, 2028, and 2029 by business segment are included below:

Business Segment 2025

Capital investments by business segment for JCP&L are included below:

JCP&L Business Segment 2023 Actual

Distribution (1)

$ 391 $ 587 $ 700

Transmission 308 371 546

Total - JCP&L $ 699 $ 958 $ 1,246

(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 2026

2027 Forecast

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2030 Forecast

(In millions)

Distribution $ 1,755 $ 2,230 $ 2,345 $ 1,930 $ 2,035

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Corporate/Other 85 135 125 140 120

Total $ 4,975 $ 5,160 $ 5,570 $ 5,995 $ 6,425

Total - FirstEnergy $ 6,015 $ 6,910 $ 7,640 $ 7,435 $ 8,260

(1) Includes capital expenditures and capital-like investments that earn a return.

(2) Consolidated plan includes Brookfield's non-controlling interest in FET

(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 2026

2027 Forecast

2028 Forecast

2029 Forecast

2030 Forecast

Distribution (1)

$ 685 $ 705 $ 770 $ 720 $ 755

Transmission 640 590 605 665 735

Total - JCP&L $ 1,325 $ 1,295 $ 1,375 $ 1,385 $ 1,490

(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.

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No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all.

Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity.

In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.

The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements.

The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with:

The remaining $2.3 billion of the purchase price was paid in cash at closing.

On July 17, 2024, Brookfield paid FE approximately $1.2 billion in full satisfaction of the promissory notes.

As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.

As of January 1, 2024, FE PA is FE’s only regulated distribution power company in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies.

So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.

Economic conditions have stabilized across numerous material categories, but not all lead times have returned to pre-pandemic levels.

Several key suppliers have seen improvements with capacity, but FirstEnergy continues to monitor the situation as demand increases across the industry, including due to data center usage.

Inflationary pressures have moderated, which has improved the cost of materials, but certain categories have remained elevated.

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 FirstEnergy’s results of operations, cash flow and financial condition.

In February 2025, the new U.S.

presidential administration announced the imposition of widespread and substantial tariffs on imports, with plans for additional tariffs to potentially be adopted in the future.

Although certain of these tariffs were subsequently temporarily stayed, the situation is dynamic and subject to rapid change.

The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on FirstEnergy's results of operations, cash flow and financial condition.

In December 2023, FirstEnergy, executed a lift-out transaction with Banner Life Insurance Company and Reinsurance Group of America that transferred approximately $683 million of plan assets and $719 million of plan obligations, associated with approximately 1,900 former competitive generation employees, who will assume future and full responsibility to fund and administer their benefit payments.

There was no change to the pension benefits for any participants as a result of the transfer.

The transaction was funded by pension plan assets and resulted in a pre-tax gain of approximately $36 million, which was included in the fourth quarter 2023 pension and OPEB mark-to-market adjustment charge.

Additionally, in January 2025, FirstEnergy executed a lift-out transaction with MetLife, that transferred approximately $640 million of plan assets and $652 million of plan obligations, associated with approximately 2,000 former competitive generation employees, who will assume future and full responsibility to fund and administer their benefit payments.

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

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.

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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.

Short-Term Borrowings / Revolving Credit Facilities

On October 24, 2024, FE and certain of its subsidiaries entered into the following amendments to each of the 2021 Credit Facilities to, among other things:

(i) extend the maturity date of the 2021 Credit Facilities for an additional one-year period, from October 18, 2027 to October 18, 2028, and (ii) increase the borrowing limit of the JCP&L credit facility from $500 million to $750 million.

Also on October 24, 2024, each of FET and KATCo entered into amendments of the 2023 Credit Facilities, to, among other things, extend the maturity date of the 2023 Credit Facilities for an additional one-year period, from October 20, 2028 to October 20, 2029 and from October 20, 2027 to October 20, 2028, for the FET credit facility and KATCo credit facility, respectively.

The 2021 Credit Facilities and 2023 Credit Facilities, as amended on October 24, 2024, are as follows:

• FE, $1.0 billion revolving credit facility;

• FET, $1.0 billion revolving credit facility;

• Ohio Companies, $800 million revolving credit facility;

• FE PA, $950 million revolving credit facility;

• JCP&L, $750 million revolving credit facility;

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

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

• KATCo, $150 million revolving credit facility.

Borrowings under the 2021 Credit Facilities and 2023 Credit Facilities may be used for working capital and other general corporate purposes.

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 2021 Credit Facilities and 2023 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities and 2023 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

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.

The 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR.

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.

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(1) Regulatory debt limitations include amounts which may be borrowed under the regulated companies’ money pool.

(2) FE is not required to maintain a debt-to-total-capitalization ratio under its credit facility.

(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 2021 Credit Facilities and 2023 Credit Facilities) expiring up to one year from the date of issuance.

The stated amount of outstanding LOCs will count against total commitments available under each of the 2021 Credit Facilities and 2023 Credit Facilities and against the applicable borrower’s borrowing sublimit.

As of December 31, 2024, FirstEnergy had $170 million in outstanding LOCs, $139 million of which are issued under the revolving credit facilities.

Revolving Credit Facility LOC Availability LOC Utilized

as of December 31, 2024

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)

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ATSI, MAIT and TrAIL 200 1

The 2021 Credit Facilities and 2023 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers.

Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the 2021 Credit Facilities and the 2023 Credit Facilities are related to the credit ratings of the company borrowing the funds.

Additionally, borrowings under each of the 2021 Credit Facilities and 2023 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.

As of December 31, 2024, FE was in compliance with its applicable consolidated interest coverage ratio and the borrowers in each case as defined under the 2021 Credit Facilities and 2023 Credit Facilities, were in compliance with their debt-to-total-capitalization ratio covenants.

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

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Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries.

As of June 1, 2024, FET no longer participated in the unregulated money pool.

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.

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Long-Term Debt Capacity

FE’s and its subsidiaries’ access to capital markets and costs of financing are influenced by the credit ratings of their securities.

The following table displays FE’s and its subsidiaries’ credit ratings as of February 25, 2025:

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 S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch

FE BBB Baa3 BBB — — — BBB- Baa3 BBB P S S

FE BBB+ Baa3 BBB — — — BBB Baa3 BBB S S S

Distribution:

CEI BBB Baa3 BBB+ — — — BBB Baa3 A- P S P

OE BBB+ A3 BBB+ A A1 A BBB+ A3 A- P S P

TE BBB+ Baa2 BBB+ A A3 A — — — P S P

FE PA BBB+ A3 BBB+ A A1 — BBB+ A3 A- P S P

JCP&L BBB A3 A- — — — BBB A3 A P S S

MP BBB Baa2 A- A- A3 A+ BBB Baa2 — S S S

CEI BBB+ Baa3 BBB+ — — — BBB+ Baa3 A- S S P

OE A- A3 BBB+ A A1 A A- A3 A- S S P

TE BBB+ Baa2 BBB+ A A3 A — — — S S P

FE PA A- A3 A- A A1 — A- A3 A S S S

JCP&L BBB+ A3 A- — — — BBB+ A3 A S S S

MP BBB Baa2 A- A- A3 A+ — Baa2 — P S S

AGC BBB- Baa2 A- — — — — — — S S S

PE BBB Baa2 BBB+ A- A3 A — — — S S S

PE BBB Baa2 BBB+ A- A3 A — — — P S S

Stand-Alone Transmission:

FET A- Baa2 BBB+ — — — BBB+ Baa2 BBB+ P S S

ATSI A- A3 A — — — A- A3 A+ P S S

MAIT A- A3 A — — — A- A3 A+ P S S

TrAIL A- A3 A — — — A- A3 A+ P S S

FET A Baa2 BBB+ — — — A- Baa2 BBB+ S S S

ATSI A A3 A — — — A A3 A+ S S S

MAIT A A3 A — — — A A3 A+ S S S

TrAIL A A3 A — — — A A3 A+ S S S

KATCo — A3 A- — — — — — — — S S

(1) S = Stable, P = Positive

The applicable undrawn and drawn margin on the 2021 Credit Facilities and 2023 Credit Facilities are subject to ratings-based pricing grids.

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

The fees paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.

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.

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Debt capacity is subject to the consolidated interest coverage ratio in FE's credit facility.

As of December 31, 2024, FirstEnergy could incur approximately $930 million of incremental interest expense or incur an approximate $2.3 billion reduction to the consolidated interest coverage earnings numerator, as defined under the covenant, and FE would remain within the limitations of the financial covenant requirements of FE's credit facility.

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

FirstEnergy has certain obligations and commitments to make future payments under contracts, including contracts executed in connection with certain of the planned construction expenditures.

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 2026 2027-2028 2029-2030 Thereafter

(In millions)

FirstEnergy (In millions)

Long-term debt (1)

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Pension funding 1,287 — 509 441 337

1,791 — 311 587 893

Total $ 45,004 $ 6,052 $ 10,015 $ 7,406 $ 21,531

Total - FirstEnergy $ 46,229 $ 3,911 $ 10,399 $ 10,008 $ 21,911

(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases.

(2) See Note 8, "Leases," of the Notes to Consolidated Financial Statements.

(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.

(5) As discussed further below, FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027.

Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Electric Companies and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier.

Although actual amounts will be determined by future customer behavior, consumption levels and power prices, management currently estimates these cash outlays will be approximately $4.1 billion in 2025.

The table above also excludes AROs, reserves for litigation, injuries and damages and environmental remediation since the amount and timing of the cash payments are uncertain.

The table also excludes accumulated deferred income taxes since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year and/or the application of the corporate AMT which, as further discussed below, is uncertain and subject to the issuance of future U.S.

As of December 31, 2025 (Undiscounted):

Total 2026 2027-2028 2029-2030 Thereafter

JCP&L (In millions)

Long-term debt (1)

$ 3,050 $ — $ — $ 350 $ 2,700

Short-term borrowings 93 93 — — —

Interest on long-term debt 1,165 143 286 258 478

Operating leases (2)

95 13 24 16 42

Finance leases (2)

Committed investments (3)

2,144 518 1,018 608 —

Total - JCP&L $ 6,551 $ 769 $ 1,330 $ 1,232 $ 3,220

(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.

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.

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However, FirstEnergy may elect to contribute to the pension plan voluntarily.

Convertible Notes

As discussed above, on May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, with a fixed interest rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023.

The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms.

However, FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.

The 2026 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets.

Proceeds from the issuance were approximately $1.48 billion, net of issuance costs.

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

• During any calendar quarter, if the last reported sale price of FE’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;

• During the five consecutive business day period immediately after any 10 consecutive trading day period in which the trading price per $1,000 principal amount of the 2026 Convertible Notes for each trading day of such 10 trading day period was less than 98% of the product of the last reported sale price of FE’s common stock and the conversion rate on each such trading day;

• Upon the occurrence of certain corporate events specified in the indenture governing the 2026 Convertible Notes.

On and after February 1, 2026, until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2026 Convertible Notes may convert all or any portion of their 2026 Convertible Notes at their option at any time at the conversion rate then in effect, irrespective of these conditions.

FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash up to the aggregate principal amount of the 2026 Convertible Notes being converted and by paying cash or delivering shares of FE’s common stock (or a combination of each), at its election, of its conversion obligation in excess of the aggregate principal amount of the 2026 Convertible Notes being converted.

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

The initial conversion price of the 2026 Convertible Notes represents a premium of approximately 20% over the last reported sale price of FE’s common stock on the New York Stock Exchange on May 1, 2023.

The conversion rate and the corresponding conversion price will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest.

FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.

If FE undergoes a fundamental change (as defined in the relevant indenture), subject to certain conditions, holders of the 2026 Convertible Notes may require FE to repurchase for cash all or any portion of their 2026 Convertible Notes at a repurchase price equal to 100% of the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date (as defined in the relevant indenture).

In addition, if certain fundamental changes occur, FE may be required, in certain circumstances, to increase the conversion rate for any 2026 Convertible Notes converted in connection with such fundamental changes by a specified number of shares of its common stock.

JCP&L is not expected to make a contribution.

Changes in Cash Position

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Net cash used for investing activities (5,065) (4,350) (3,652)

Net cash provided from (used for) financing activities 1,434 2,238 (912)

Net cash provided from financing activities 1,310 1,434 2,238

Net change in cash, cash equivalents and restricted cash (55) (25) (27)

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The increase in cash from operating activities in 2025 from 2024 is primarily due to:

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

• The return of cash collateral in 2024 that was previously posted with PJM, which was replaced with issuances of letters of credit;

• The absence of cash collateral returned to certain generation suppliers that serve shopping customers during 2023 that was previously received as a result of changes in power prices;

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

• Receipt of the derivative lawsuit settlement proceeds in the second quarter of 2024;

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

• 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;

• 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:

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

• Higher payments associated with Pennsylvania gross receipts taxes;

• Payment of the SEC civil penalty and OAG settlement in the third quarter of 2024.

FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category.

The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2024, 2023 and 2022:

For the Years Ended December 31,

(In millions) 2024 2023 2022

CASH FLOWS FROM OPERATING ACTIVITIES:

Income (loss) from discontinued operations $ — $ (21) $ —

Loss (gain) on disposal, net of tax — 21 —

• 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;

• Decreased cash collateral received from suppliers due to changes in power prices.

Cash Flows From Investing Activities

Cash used for investing activities in 2024 principally represented cash used for capital investments.

The following table summarizes cash used for investing activities for the years ended 2024, 2023 and 2022:

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,

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$ 5,065 $ 4,350 $ 3,652

Cash used for investing activities during 2024 increased $698 million, compared to 2023, primarily due to higher planned capital investment spend.

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

Cash provided from (used for) financing activities was $1,434 million, $2,238 million, and $(912) million in 2024, 2023, and 2022, respectively.

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.

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(In millions)

Unsecured notes $ 2,100 $ 1,050 $ 300

Senior unsecured notes $ 3,125 $ 2,100 $ 1,050

Unsecured convertible notes 2,500 — 1,500

FMBs 200 — 600

Senior secured notes 100 — —

5,925 2,100 3,150

Redemptions / Repayments

Unsecured notes (2,013) (494) (2,737)

Unsecured convertible notes (1,206) — —

Senior unsecured notes (1,875) (2,013) (494)

FMBs — (700) —

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Proceeds from FET Equity Interest Sale (Note 1.) — 3,500 —

Proceeds from 19.9% FET equity interest sale, net of transaction costs — — 2,348

Noncontrolling interest cash distributions (100) (86) (72)

Capital contributions from noncontrolling interest — — 9

Short-term borrowings, net (225) (225) 675

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(In millions) Description

Redemptions (1)

FE Unsecured Notes April, 2024 7.38% 2031 $463 FE redeemed all of its remaining $463 million of 2031 Notes including a premium of approximately $80 million ($63 million after-tax).

In addition, FE recognized approximately $4 million ($3 million after-tax) of deferred cash flow hedge losses and $1 million in other unamortized debt costs and fees associated with the FE debt redemptions.

JCP&L Unsecured Notes April, 2024 4.70% 2024 $500 JCP&L redeemed unsecured notes that became due.

MP FMBs April, 2024 4.10% 2024 $400 MP redeemed FMBs that became due.

CEI FMBs August, 2024 5.50% 2024 $300 CEI redeemed FMBs that became due.

FE PA Unsecured Notes December, 2024 4.00% 2025 $250 On December 30, 2024, FE PA caused to be redeemed $250 million of 4.00% senior notes due 2025.

FE PA Unsecured Notes December, 2024 4.15% 2025 $200 On December 30, 2024, FE PA caused to be redeemed $200 million of 4.15% senior notes due 2025.

FET Unsecured Notes December, 2024 4.35% 2025 $600 On December 30, 2024, FET caused to be redeemed $600 million of 4.35% senior notes due 2025.

ATSI Unsecured Notes March, 2024 5.63% 2034 $150 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.

MAIT Unsecured Notes May, 2024 5.94% 2034 $250 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.

FET Unsecured Notes with registration rights September, 2024 4.55% 2030 $400 Proceeds were used to repay short-term borrowings, to redeem FET's $600 million 4.35% notes due 2025, to finance capital expenditures and for other general corporate purposes.

FET Unsecured Notes with registration rights September, 2024 5.00% 2035 $400 Proceeds were used to repay short-term borrowings, to redeem FET's $600 million 4.35% notes due 2025, to finance capital expenditures and for other general corporate purposes.

KATCo Unsecured Notes November, 2024 5.17% 2035 $200 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.

JCP&L Unsecured Notes with registration rights December, 2024 5.10% 2035 $700 Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.

(1) Excludes principal payments on securitized bonds.

As noted above, on September 5, 2024, FET issued $400 million of unsecured senior notes due in 2030 and $400 million of unsecured senior notes due in 2035 in a private offering that included a registration rights agreement in which FET agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act.

On October 8, 2024, FET filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on December 20, 2024.

On January 24, 2025, FET completed an exchange offer of these senior notes for like principal amounts registered under the Securities Act.

As noted above, on December 5, 2024, JCP&L issued $700 million of unsecured senior notes due in 2035 in a private offering that included a registration rights agreement in which JCP&L agreed to conduct an exchange offer of these senior notes for like principal amounts registered under the Securities Act.

JCP&L also agreed to file a shelf registration statement with the SEC to cover resales of the senior notes under certain circumstances.

In the event that JCP&L's exchange offer is not completed or the shelf registration statement, if required, is not effective by the 366th day after December 5, 2024, or the effective shelf registration stops being effective for 60 days during any 12-month period, then additional interest will accrue on the coupon.

Interest will accrue at a rate of 25 basis points for the first 90 days and an additional 25 basis points in the subsequent 90-day period, but not to exceed 50 basis points per year.

However, if the additional interest is triggered, the interest rate will reset to the original notes rate once the registration statement is effective, or the shelf registration, if required, becomes effective.

JCP&L plans to file a registration statement for the exchange offer before the end of the first quarter of 2025.

FE Senior Unsecured Notes March, 2025 2.05% 2025 $300 FE redeemed unsecured notes that became due.

TrAIL Senior Unsecured Notes May, 2025 3.76% 2025 $75 TrAIL redeemed unsecured notes that became due.

TrAIL Senior Unsecured Notes June, 2025 3.85% 2025 $550 TrAIL redeemed unsecured notes that became due.

FE Senior Unsecured Convertible Notes June, 2025 4.00% 2026 $1,206 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 4.30% 2026 $650 On October 16, 2025, JCP&L redeemed $650 million of 4.30% senior notes due 2026.

FE Senior Unsecured Notes December, 2025 1.60% 2026 $300 On December 31, 2025, FE redeemed $300 million of 1.60% senior notes due 2026.

TrAIL Senior Unsecured Notes April, 2025 5.00% 2031 $600 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 5.00% 2030 $225 Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.

OE Senior Unsecured Notes May, 2025 4.95% 2029 $300 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 5.00% 2031 $200 Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.

PE FMBs June, 2025 5.00% 2030 $200 Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.

TE Senior Secured Notes June, 2025 5.18% 2030 $100 Proceeds were used to refinance existing debt, to finance capital expenditures, for working capital, and for other general corporate purposes.

FE Senior Unsecured Convertible Notes June, 2025 3.63% 2029 $1,350 Proceeds were used to refinance existing debt, to repurchase a portion of its 2026 Convertible Notes, and for other general corporate purposes.

FE Senior Unsecured Convertible Notes June, 2025 3.88% 2031 $1,150 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 4.75% 2033 $450 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 4.15% 2029 $350 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 4.40% 2031 $500 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 5.15% 2036 $500 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 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;

• 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.

GUARANTEES AND OTHER ASSURANCES

FIRSTENERGY - GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business.

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FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.

As of December 31, 2024, outstanding guarantees and other assurances aggregated approximately $923 million, consisting of parental guarantees on behalf of its consolidated subsidiaries ($495 million) and other assurances ($428 million).

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

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These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral.

See Note 15, "Commitments, Guarantees and Contingencies," of the Notes to Consolidated Financial Statements for more information.

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 uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations.

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.

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As of December 31, 2025, the FirstEnergy pension plan assets were allocated approximately as follows:

25% in public equity securities, 23% in fixed income securities, 4% in hedge funds, 1% in insurance-linked securities, (1)% in derivatives, 9% in real estate funds, 20% in private equity and debt funds and 19% in cash and short-term securities.

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 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans.

During 2024, FirstEnergy's pension plan assets have lost approximately 0.4% as compared to an annual expected return on plan assets of 8.0%, and FirstEnergy's OPEB plan assets have gained approximately 13.4% as compared to an annual expected return on plan assets of 7.0%.

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

FirstEnergy’s exposure to fluctuations in market interest rates is largely mitigated as all long-term debt, with the exception of the 2021 Credit Facilities and the 2023 Credit Facilities, has fixed interest rates, as noted in the table below.

However, FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities.

Comparison of Carrying Value to Fair Value as of December 31, 2024

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 2026 2027 2028 2029 2030 There-after Total Fair Value

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Average interest rate 4.5 % 3.8 % 3.8 % 3.9 % 3.8 % 4.7 % 4.4 %

FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement (which occurred during the second quarter of 2023).

JCP&L - Comparison of Carrying Value to Fair Value as of December 31, 2025

Year of Maturity or Notice of Redemption 2026 2027 2028 2029 2030 There-after Total Fair Value

(In millions)

Investments Other Than Cash and Cash Equivalents:

Fixed Income $ — $ — $ — $ — $ — $ 280 $ 280 $ 280

Average interest rate — % — % — % — % — % 3.4 % 3.4 %

Long-term Debt:

Fixed rate $ — $ — $ — $ 350 $ — $ 2,700 $ 3,050 $ 3,059

Average interest rate — % — % — % 4.2 % — % 4.8 % 4.7 %

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.

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Changes in asset performance and discount rates will not impact these pension costs during the year, however, future years could be impacted by changes in the market.

On May 12, 2023, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan.

The size of the voluntary contribution made on May 12, 2023, in relation to total pension assets triggered a remeasurement of the pension plan.

FirstEnergy elected the practical expedient to remeasure pension plan assets and obligations as of April 30, 2023, which is the month-end closest to the date of the voluntary contribution.

FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows.

The discount rate used to measure pension obligations was 5.72% as of December 31, 2024 compared to 4.94% as of April 30, 2023 and 5.05% as of December 31, 2023.

The discount rate used to measure OPEB obligations was 5.60% as of December 31, 2024 as compared to 4.97% as of December 31, 2023.

The 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR.

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.

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Economic Conditions

Economic conditions have stabilized across numerous material categories, but not all lead times have returned to pre-pandemic levels.

Several key suppliers have seen improvements with capacity, but FirstEnergy continues to monitor the situation as demand increases across the industry, including due to data center usage.

Inflationary pressures have moderated, which has improved the cost of materials, but certain categories have remained elevated.

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.

In February 2025, the new U.S.

presidential administration announced the imposition of widespread and substantial tariffs on imports, with plans for additional tariffs to potentially be adopted in the future.

Although certain of these tariffs were subsequently temporarily stayed, the situation is dynamic and subject to rapid change.

The imposition of these or any other new or increased tariffs or resultant trade wars could have an adverse effect on FirstEnergy's results of operations, cash flow and financial condition.

Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations.

FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk.

FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies.

These concentrations may impact FirstEnergy's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.

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.

FirstEnergy's credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements.

FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

The IRA of 2022, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion.

The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT.

The IRA of 2022 requires the U.S.

Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid.

On September 12, 2024, the U.S.

Treasury issued proposed regulations for the AMT for comments.

FirstEnergy is assessing the proposed regulations but continues to believe that it is more likely than not it will be subject to AMT, however, the completion of the U.S.

Treasury’s rulemaking process and the future issuance of final regulations, as well as potential future federal tax legislation or presidential executive orders, could significantly change FirstEnergy’s AMT estimates or its conclusion as to whether it is an AMT payer at all.

As further discussed below, FirstEnergy expects to pay regular federal corporate income tax for the 2024 tax year, due in large part to the gain realized from closing the FET Equity Interest Sale.

The regulatory treatment of the IRA of 2022 may also be subject to regulation by FERC and/or applicable state regulatory authorities.

Any adverse development in the IRA of 2022, including guidance from the U.S.

Treasury and/or the IRS or unfavorable regulatory treatment, could negatively impact FirstEnergy’s cash flows, results of operations and financial condition.

As discussed above, on March 25, 2024, FirstEnergy closed on the FET Equity Interest Sale realizing an approximate $7 billion tax gain from the combined sale of 49.9% of the equity interests of FET for consideration received and recapture of negative tax basis in FET.

As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards available to offset a majority of the tax gain and expected taxable income in 2024.

Due to certain limitations on NOL utilization enacted in the Tax Act, approximately $1.6 billion NOL will carry forward into 2025 and possibly beyond.

In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% FET equity interest sale in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA consolidation, and recognized a reduction to OPIC of approximately $803 million for federal and state income tax associated with the tax gain from closing on the FET Equity Interest Sale.

Previously, in the fourth quarter of 2023, FirstEnergy recognized a charge to income tax expense of approximately $58 million as a true-up of the deferred tax liability associated with the deferred tax gain.

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.

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

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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 Allowed ROE

CEI May 2009 51%/ 49%

Company Rates Effective For Customers Allowed Debt/Equity Capital Structure Allowed ROE

May 2009 51%/ 49%

January 2025 Settled (2)

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JCP&L June 2024 48.1% / 51.9%

OE January 2009 51% /49%

January 2009 51% /49%

PE (West Virginia) March 2024 Settled (2)

PE (Maryland) October 2023 47% / 53%

TE January 2009 51% / 49%

(1) As further discussed below, new rates became effective for customers on January 1, 2025, and did not disclose allowed debt/equity and ROE rates.

January 2009 51% / 49%

(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.

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PE recovers its costs plus a return for providing SOS.

The EmPOWER Maryland program previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings.

The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter.

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.

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In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively.

The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023.

On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications.

On August 15, 2024, in accordance with the MDPSC directive, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million.

On December 27, 2024, the MDPSC issued an order approving PE’s revised plan.

PE recovers EmPOWER program costs with a return on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period.

Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding.

Consistent with a December 29, 2022, order by the MDPSC phasing out the unamortized balances of EmPOWER investments, PE is required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025, and 100% in 2026 and beyond.

Notwithstanding the order to phase out the unamortized balances of EmPOWER investments, all previously unamortized costs for prior cycles were to be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023.

In the 2024-2026 order issued on December 29, 2023, the period to pay down the unamortized balances was extended through the end of 2030.

On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years.

On November 27, 2024, PE filed for approval of revised tariff pages reflecting an update of the PE tariff becoming effective in 2025, which included the requested analysis of alternative amortization methods.

On December 18, 2024, the MDPSC approved the revised tariff pages permitting PE to continue to use its preferred amortization method.

New legislation signed into law on May 9, 2024, and effective July 1, 2024, is expected to reduce

the return on the EmPOWER unamortized balances for PE by a total of $25 to $30 million over the period of 2024-2030.

On July 31, 2024, the MDPSC issued an order implementing revised EmPOWER surcharge rates for PE in accordance with the new law and denying PE’s request for a hearing that sought to challenge certain portions of the law.

On August 30, 2024, PE filed a petition seeking judicial review of its challenge to the law.

The MDPSC and Maryland Office of People’s Counsel filed intents to participate.

On November 15, 2024, the parties filed a joint motion to postpone the February 7, 2025 hearing date scheduled by the court and proposed a briefing schedule.

The motion was granted on December 28, 2024.

PE filed a Petitioner Memorandum on December 17, 2024.

The MDPSC and Maryland Office of People’s Counsel filed a Response Memorandum on January 28, 2025.

PE filed a Reply Memorandum on February 20, 2025.

A hearing is scheduled for March 7, 2025.

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.

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.

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All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

The base rate increase approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and became effective for customers on June 1, 2024.

Until those new rates became effective for customers, JCP&L was amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period.

Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million.

Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.

JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021.

The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis.

On May 22, 2024, the NJBPU approved JCP&L’s request for a six-month extension of the EE&C Plan I, to December 31, 2024.

The budget for the extension period adds approximately $69 million to the original program cost and JCP&L will recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders.

On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and had a proposed budget of approximately $964 million.

EE&C Plan II, as filed, consisted of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program.

Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II.

On October 30, 2024, the NJBPU approved the parties’ stipulation of settlement, wherein the parties agreed to a budget of approximately $817 million for EE&C Plan II, including $784 million of investments that will earn a return on equity of 9.6%, with an equity ratio of 52%, and be recovered over 10 years.

The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021.

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JCP&L and one other party filed comments on July 31, 2023.

On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid.

On 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.

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On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs.

Orsted’s cancellation does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure.

Construction is expected to begin in 2025.

Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the DOE to finance a substantial portion of the project using low-interest rate loans available under the DOE’s

Energy Infrastructure Reinvestment Program of the IRA of 2022.

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.

JCP&L submitted the second part of its two-part application on March 13, 2024, which was approved on May 17, 2024.

The DOE Loan Program Office has initiated a due diligence review of the application.

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.

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EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years.

JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition.

The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009.

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.

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.

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.

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Many of the terms and conditions were to be reconsidered in the base rate case.

The ESP V order additionally directed the Ohio Companies to file another base distribution rate case not later than May 31, 2028, and contribute $32.5 million during the term of ESP V to fund low-income customer bill assistance programs and bill assistance for income-eligible senior citizens, and to develop an electric vehicle education program to assist customers in transitioning to electric vehicles which was recognized in the second quarter of 2024 within “Other operating expenses” at the Regulated Distribution segment and on FirstEnergy’s Consolidated Statements of Income.

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.

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On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV.

On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI, for a term beginning on the date new base distribution rates from the pending base rate case go into effect, in an effort to align with the ongoing base distribution rate case, and continuing through May 31, 2028.

ESP VI proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, and proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual reliability performance-based revenue cap increases of $37 to $43 million, and an AMI rider for recovery of approved grid modernization investments.

ESP VI additionally proposes riders to support continued maintenance of the distribution system, including recovery of vegetation management and storm restoration

operations and maintenance expenses.

In addition, ESP VI proposes energy efficiency programs for low-income customers, and includes a commitment to spend $6.5 million annually over the ESP VI term, without recovery from customers, on initiatives to assist low-income customers, as well as education and incentives to help ensure customers have good experiences with electric vehicles.

The PUCO has scheduled a technical conference for March 12, 2025.

On 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.

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 compared to test period revenues, with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI.

Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others.

On June 14, 2024, the Ohio Companies filed supporting testimony.

On July 31, 2024, the Ohio Companies filed an update that adjusted the net increase in base distribution revenues to approximately $190 million compared to test period revenues and incorporated matters in the rate case as directed by the PUCO’s ESP V order.

On January 27, 2025, the Ohio Companies filed a notice in the base rate case notifying parties that they will update their application for an increase in base distribution rates to reflect the withdrawal of ESP V and the reversion to ESP IV.

The PUCO Staff hired a third party to assist in the review of the Ohio Companies' base rate case filing, and on February 21, 2025, PUCO staff and the third party auditor each filed their reports.

PUCO staff’s report takes limited positions on the auditor’s finding and recommendations and makes additional findings.

The Ohio Companies plan to respond and file supplemental testimony by March 24, 2025.

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.

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.

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.

On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits.

The Ohio Companies proposed that phase two would be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period.

Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV.

On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan, which was approved by the PUCO on December 18, 2024 and implementation has since begun.

The stipulation provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters.

Phase two of the distribution grid modernization plan, as modified by the stipulation, would be completed over a four-year budget period with estimated capital investments of approximately $421 million.

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.

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On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below and on November 22, 2024, the administrative law judge ordered that the bifurcated portion of the corporate separation audit, discussed further below, be consolidated with the already-consolidated DMR audit and expanded DCR rider audit proceeding.

Evidentiary hearings are scheduled to begin May 13, 2025.

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 thousand.

On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor.

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The audit examined 53 payments totaling approximately $75 million made in support of the passage of HB 6 and subsequent referendum efforts, and concluded that less than $5 million was allocated to the Ohio Companies.

The audit report affirmed the Ohio Companies’ conclusion in its August 6, 2021 filing that a rate impact of less than $15 thousand was charged to the Ohio Companies’ pole attachment customers associated with political and charitable spending in support of HB 6.

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.

The parties' comments remain pending with the PUCO.

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.

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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.

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.

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Evidentiary hearings were held on October 9 and 10, 2024;

the scope of the hearings excluded allegations involving activities related to the passage of HB 6 and the former PUCO chairman, which will be addressed at a later time.

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.

To the extent the PUCO ultimately accepts the intervenors’ recommendations and issues a fine to the Ohio Companies, such amount is not expected to be material.

• On September 3, 2024, the Ohio Companies filed an application to amend their corporate separation plan to incorporate certain recommendations from prior audit reports, which include, but are not limited to, improving controls for non-regulated competitive employees’ physical space and access to data, updating and implementing a process to annually review the cost allocation manual, developing state specific codes of conduct practices, and implementing additional training related to the cost allocation manual and the state codes of conduct.

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On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, and further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement.

On November 22, 2024, the administrative law judge ordered that the bifurcated portion of the corporate separation audit be consolidated with the

already-consolidated DMR audit and the expanded DCR rider audit proceeding.

Evidentiary hearings are scheduled to begin May 13, 2025.

On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023.

On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans.

On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing.

As the PUCO did not rule on OCC’s November 17, 2023 application for rehearing within 30 days of filing, the application for rehearing was denied by operation of law.

Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect.

Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities.

The Ohio Companies contested the motions, which are pending before the PUCO.

See “Outlook - Other Legal Proceedings” below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.

On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA.

As a result of the PA Consolidation, FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University.

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.

FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University.

The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.

FE PA operates under rates approved by the PPUC, effective as of January 1, 2025, as further discussed below.

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 through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.

Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for accelerated infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs.

On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives.

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

The PPUC approved FE PA’s application on December 19, 2024, and implementation began in January 2025.

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

On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023.

On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale.

On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded.

On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years.

The settlement was approved by the PPUC on March 14, 2024.

The transaction closed on March 25, 2024.

On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year.

The rate case requested a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflected a roll-in of several current riders such as DSIC, Tax Act and smart meter.

The increase represented an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase.

Key components of the base rate case filing included a proposal to change pension recovery from average cash contributions to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension expense requested in the proceeding and the actual annual amount each year using this method.

Additionally, FE PA requested an enhanced ten-year vegetation management

program and recovery of certain incurred costs, including major storms, COVID-19, a program to convert streetlights to LEDs, and others.

On September 13, 2024, FE PA and the active parties to the proceeding filed a joint settlement agreement requesting that the administrative law judges to approve FE PA’s requested distribution base rate case increase subject to the terms and conditions of the settlement, which included, among other things, an annual net revenue increase of $225 million.

Other key components of the settlement agreement included recovery of costs incurred for storms and COVID-19, additional cost recovery of ongoing storm costs, inspection and maintenance of overhead lines and transformers, and rate case expenses, as well as an enhanced vegetation management program.

On October 15, 2024, the administrative law judges issued a decision recommending that the PPUC approve, without modification, the September 13, 2024 settlement agreement.

On November 21, 2024, the PPUC unanimously approved the settlement agreement without modification.

New rates became effective on January 1, 2025.

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.

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.

On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates.

This increase, which was driven primarily by higher fuel expenses, included the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023).

The remaining $75.6 million of the under recovery balance not recovered in 2024 was to be deferred for collection during 2025, with an annual carrying charge of 4%.

A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC.

The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026.

There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing, neither of which occurred.

An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.

MP and PE will file their next ENEC filing on or before September 1, 2025.

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.

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The surcharge went into effect January 1, 2024.

The first solar generation site went into service in January 2024 and the second solar generation site went into service in September 2024.

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.

On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets.

Specifically, MP and PE were seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets.

Any depreciation rates approved by the WVPSC would not become effective until new base rates were established.

On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024.

An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and new depreciation rates became effective on April 1, 2024.

On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method.

Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments.

On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit.

On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC.

An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlements with slight non-material modifications with new rates going into effect on March 27, 2024.

Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.

See “Outlook - Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.

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.

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

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Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.

The following table summarizes the key terms of FERC rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2025:

Company Rates Effective Capital Structure Allowed ROE

ATSI January 2015 Actual (13-month average) 9.88% (1)

January 2020 Actual (13-month average) 10.20%

MP January 2021 Lower of Actual (13-month average) or 56% equity

PE January 2021 Lower of Actual (13-month average) or 56% equity

January 2021 Hypothetical 49.3% equity (3)

MAIT July 2017 Lower of Actual (13-month average) or 60%

TrAIL July 2008 Actual (year-end) 12.7% (2) / 11.7% (3)

Company Allowed Debt/Equity Capital Structure Allowed ROE

ATSI Actual (13-month average) 9.88% (1)

Actual (13-month average) 10.2%

MP Lower of Actual (13-month average) or 56% equity

PE Lower of Actual (13-month average) or 56% equity

49.3% equity (3)

MAIT Lower of Actual (13-month average) or 60% equity

TrAIL Actual (year-end) 12.7% (4) / 11.7% (5)

(1) Reflects a 0.5% reduction to the 10.38% approved ROE due to the January 2025 Sixth Circuit ruling eliminating the 50 basis point adder associated with RTO membership (see Transmission ROE Incentive ).

(2) On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.

(3) Hypothetical capital structure will convert to an actual (13-month average) in January 2027

(3) Capital structure will convert to an actual (13-month average) in January 2027.

(4) TrAIL the Line and Black Oak Static Var Compensator.

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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.

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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.

February 4, 2022, FERC filed the final audit report for the period of January 1, 2015, through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted.

The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting.

Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis.

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 recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods.

FirstEnergy has recovered approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements as of December 31, 2024.

These reclassifications also resulted in a reduction to the Stand-Alone Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings.

The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Stand-Alone Transmission segment and on FirstEnergy’s Consolidated Statements of Income.

Furthermore, the Ohio Companies are in the process of addressing the outcomes of the FERC Audit with the PUCO, which includes seeking continued rate base treatment of approximately $100 million of certain corporate support costs allocated to distribution capital assets in Ohio.

On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review.

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, the FERC Office of Enforcement issued a set of data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy responded.

The FERC Office of Enforcement issued another set of data requests related to the same fuel consulting contract on January 13, 2025.

Responses are due March 5, 2025.

If the FERC Office of Energy Market Regulation and the FERC Office of Enforcement were to successfully challenge the recovery of the 2022 reclassified operating expenses and formula transmission rates it could have material adverse effect on FirstEnergy financial conditions, result of operations, and cash flows.

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 affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022.

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, but granted it as to AEP.

AEP and OCC appealed FERC’s orders to the Sixth Circuit.

On January 17, 2025, the Sixth Circuit ruled that the 50 basis point adder is available only where RTO membership is voluntary, that Ohio law requires Ohio’s transmission utilities to be members of an RTO, and that it was unlawful for FERC to excise the adder from AEP rates, but not from the Duke and ATSI rates.

FirstEnergy expects to pursue further appeal.

During the fourth quarter of 2024, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the Consolidated Statements of Income at the Stand-Alone Transmission segment to reflect the expected refund owed to transmission customers back to February 24, 2022.

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.

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

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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

Ohio Consumers Counsel v ATSI, et al.

On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system.

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and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold.

ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.

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

Industrial Energy Consumers of America, et al.

Avista Corporation, et al.

On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates.

The complaint demands that FERC:

(i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100kV or higher, (ii) appoint “independent transmission monitors” to conduct such planning, and (iii) condition construction of local transmission facilities on the facility having been planned by the “independent transmission monitor.” FirstEnergy expects to participate in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI.

FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy’s transmission capital investment strategy.

(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.

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 FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters.

While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies.

FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

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

CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually.

CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions.

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 NOx and SO 2 emissions from power plants in 13 states, including West Virginia.

This followed the 2014 U.S.

Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states.

The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017.

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.

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Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.

Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards.

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.

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On October 29, 2019, the State of New York appealed the denial of its petition to the D.C.

On July 14, 2020,

On July 14, 2020, the D.C.

Circuit reversed and remanded the New York petition to the EPA for further consideration.

On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition.

In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements.

On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards.

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.

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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.

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.

On September 25, 2023, the D.C.

Circuit denied the motions to stay the Good Neighbor Plan.

On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the U.S.

Supreme Court.

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 U.S.

Supreme Court granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C.

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.

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.

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, regulators in the U.S.

In recent years, certain regulators in the U.S.

have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts.

There are several initiatives to reduce GHG emissions at the state and international level.

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.

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 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.

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FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions).

Our ability to achieve our GHG reduction goal is subject to our ability to make operational changes and is conditioned upon numerous risks, many of which are outside of our control.

With respect to our coal-fired plants in West Virginia, which serve as the primary source of our Scope 1 emissions, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison.

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 MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow.

FirstEnergy cannot currently estimate the financial impact of climate change policies, including the final SEC climate disclosure rules, which are currently stayed, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants.

Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO 2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs.

Numerous states and private parties filed appeals and motions to stay the CPP with the D.C.

Circuit in October 2015.

On February 9, 2016, the U.S.

Supreme Court stayed the rule during the pendency of the challenges to the D.C.

Circuit and U.S.

Supreme Court.

On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate.

On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation.

On January 19, 2021, the D.C.

Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void.

Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule.

Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs.

On June 30, 2022, the U.S.

Supreme Court in West Virginia v.

Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration.

In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v.

Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO 2 emissions) from fossil fuel based EGUs.

The rule, which proposed stringent GHG emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024.

In May 2024, a group of 25 states, including West Virginia, filed a challenge to the

rule in the D.C.

On July 19, 2024, the D.C.

Circuit denied the stay motions and on July 23 and 26, 2024 the aggrieved petitioners filed emergency stay applications to the U.S.

Supreme Court.

On October 16, 2024, the U.S.

Supreme Court denied the stay applications.

On December 6, 2024, oral arguments on the merits of the challenge were heard by the D.C.

On February 5, 2025, the Department of Justice filed an unopposed motion on behalf of EPA in the D.C.

Circuit, seeking to hold the litigation in abeyance, and forego issuing its opinion, for a period of 60 days while the new leadership at EPA evaluates the rule and determines how it wishes to proceed On February 19, 2025, the D.C.

Circuit granted EPA’s motion.

Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft.

Martin and Harrison power stations.

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 litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.

FirstEnergy continues to monitor climate change policies at both the federal and state level.

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

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On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.

The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023.

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.

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In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date.

On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate.

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.

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A number of other parties have challenged the final rule in various petitions for review across several circuits.

Those petitions and motions for stay have been consolidated and will be reviewed by the U.S.

Court of Appeals for the Eighth Circuit Court.

On October 10, 2024, the Eighth Circuit denied the motions for stay.

Depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft.

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.

FirstEnergy is currently assessing the impact of the final 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

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Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants.

On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations.

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As of May 31, 2024, AE Supply ceased accepting waste at the McElroy’s Run CCR impoundment facility from Pleasants Power Station.

As of December 31, 2024, AE Supply continues to operate the dry landfill adjacent to McElroy’s Run as a disposal facility for Pleasants Power Station.

The agreement requires AE Supply to establish a $160 million escrow account that AE Supply will fund over five years.

The escrow funding obligation will be secured by a surety bond, which will be guaranteed by FE.

On May 8, 2024, the EPA finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments.

The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule.

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.

Depending on the outcome of appeals and the ultimate implementation of the final rule, compliance with these standards could require remedial actions, including removal of coal ash.

See Note 8, “Asset Retirement Obligations,” above for a description of the $139 million increase to its ARO that FirstEnergy recorded during 2024 as a result of its analysis.

FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA.

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;

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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.

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Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S.

(ii) pay a criminal monetary penalty totaling $230 million within sixty days, consisting of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers;

(ii) pay a criminal monetary penalty totaling $230 million within sixty days, consisting of (x) $115 million paid by FE to the U.S.

Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers;

(iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA;

(iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities;

and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S.

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 expense in the second quarter of 2021 and paid in the third quarter of 2021.

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;

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;

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Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S.

Attorney’s Office, including the aforementioned January 17, 2025, indictment.

Attorney’s Office, including the aforementioned federal indictment against two former FirstEnergy

senior officers.

Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S.

Attorney’s Office will dismiss the criminal information.

Legal Proceedings Relating to United States v.

On February 26, 2025, the U.S.

Attorney’s Office filed a status report confirming these commitments.

Legal Proceedings Relating to U.S.

Larry Householder, et al.

On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied.

FirstEnergy cooperated fully with the SEC investigation, and on September 12, 2024, the SEC issued a settlement order that concluded and resolved the investigation in its entirety.

On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA.

Householder brought in Cuyahoga County, Ohio.

FirstEnergy is cooperating with the OOCIC in its investigation.

On August 12, 2024, FirstEnergy entered into a settlement with the OAG's Office and the Summit County Prosecutor’s Office to resolve both the OOCIC investigation and State of Ohio ex rel.

Dave Yost, Ohio Attorney General v.

FirstEnergy Corp., et al.

and City of Cincinnati and City of Columbus v.

FirstEnergy Corp., noted below.

In addition to the subpoenas referenced above under “ United States v.

Larry Householder, et.

” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr.

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.

The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted).

Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

• In re FirstEnergy Corp.

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The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions concerning FE’s business and results of operations.

The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020.

The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020.

On March 30, 2023, the court granted plaintiffs’ motion for class certification.

On April 14, 2023, FE filed a petition in the U.S.

Court of Appeals for the Sixth Circuit seeking to appeal that order;

the Sixth Circuit granted FE’s petition on November 16, 2023, and heard oral argument on July 17, 2024.

On November 30, 2023, FE filed a motion with the S.D.

Ohio to stay all proceedings pending that circuit court appeal.

Discovery was stayed during the pendency of that motion to stay all proceedings and on August 20, 2024, the S.D.

Ohio denied FE’s motion and lifted the stay as to fact discovery.

On July 29, 2024, FE filed in the U.S.

Court of Appeals for the Sixth Circuit a Petition for Writ of Mandamus asking the Sixth Circuit to direct the district court to deny plaintiffs’ motion to compel disclosure of FE’s privileged internal investigation materials.

On September 11, 2024, FE filed in the U.S.

Court of Appeals for the Sixth Circuit a motion to stay discovery of the privileged internal investigation materials pending resolution of the Petition for Writ of Mandamus.

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.

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FirstEnergy Corp., et al.

on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH.

on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain then-current and former officers of Energy Harbor Corp.

The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp.

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Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

• State of Ohio ex rel.

Dave Yost, Ohio Attorney General v.

FirstEnergy Corp., et al.

and City of Cincinnati and City of Columbus v.

FirstEnergy Corp.

(Common Pleas Court, Franklin County, OH, all actions have been consolidated);

on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related claims in connection with the passage of HB 6.

On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider.

On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues.

In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero.

On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills included new decoupling rider charges after February 8, 2021.

On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy.

On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit.

This matter was stayed through a criminal trial in United States v.

Larry Householder, et al .

described above, but resumed pursuant to an order, dated March 15, 2023.

On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed.

On February 16, 2024, the OAG moved to stay discovery in the case in light of the February 9, 2024, indictments against defendants in this action, which the court granted on March 14, 2024.

As described above, FE reached a settlement with the OAG of this civil action and the OOCIC investigation, which resolves this civil action.

FE recognized a loss contingency of $19.5 million in the second quarter of 2024, which was paid on August 16, 2024.

On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr.

Householder that were filed in the S.D.

Ohio, the N.D.

Ohio, and the Ohio Court of Common Pleas, Summit County:

• Gendrich v.

Anderson, et al.

(Common Pleas Court, Summit County, Ohio, all actions have been consolidated);

on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty.

On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.

Anderson, et al.

on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act.

On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D.

Ohio based upon the approval of the settlement by the S.D.

Ohio, which was granted on May 17, 2024.

• Bloom, et al.

Anderson, et al.;

Employees Retirement System of the City of St.

Jones, et al.;

Electrical Workers Pension Fund, Local 103, I.B.E.W.

Anderson et al.;

Massachusetts Laborers Pension Fund v.

Anderson et al.;

The City of Philadelphia Board of Pensions and Retirement v.

Anderson et al.;

Dowling et al.;

Anderson, et al.

Ohio, all actions have been consolidated);

on September 1, 2020, purported stockholders of FE filed shareholder derivative actions alleging the then FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act.

On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D.

Ohio, which the S.D.

Ohio granted on May 9, 2022.

Subsequently, following a hearing on August 4, 2022, the S.D.

Ohio granted final approval of the settlement on August 23, 2022, which was appealed by a purported FE stockholder on June 15, 2023.

Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval.

All appeal options were exhausted on May 16, 2024.

The judgment and settlement are final and, therefore, the derivative lawsuits are now fully resolved.

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

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 FirstEnergy’s normal business operations pending against FE or its subsidiaries.

The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries.

The other potentially material items not otherwise discussed above are described under Note 13, “Regulatory Matters.”

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs.

In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can

If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations, and cash flows.

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

FirstEnergy prepares consolidated financial statements in accordance with GAAP.

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.

FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements.

Additional information regarding the application of accounting policies is included in the Notes to Consolidated Financial Statements.

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

FirstEnergy is involved in a number of investigations, litigation, regulatory audits, arbitration, mediation, and similar proceedings, including those surrounding HB 6.

FirstEnergy regularly assesses its liabilities and contingencies in connection with asserted or potential matters and establishes reserves when appropriate.

In the preparation of the financial statements, FirstEnergy makes judgments regarding the future outcome of contingent events based on currently available information and accrues liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs.

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 14, “Regulatory Matters” and Note 15, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements for additional information.

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.

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

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

FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period.

The 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.

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The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.

Transmission revenues are primarily derived from forward-looking formula rates.

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.

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Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.

FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.

See Note 2, "Revenue," of the Notes to Consolidated Financial Statements for additional information.

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

FE's subsidiaries are subject to regulation that sets the prices (rates) the Electric Companies and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered.

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.

FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur.

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, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently

recorded regulatory assets and liabilities will be recovered or settled in future rates.

If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings.

FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next year's recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets.

See Note 14, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.

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 noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees.

FirstEnergy provides a modest amount of noncontributory life insurance to retired employees in addition to optional contributory insurance to a closed group of retired employees.

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 also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy pension and OPEB obligations are based on various assumptions in calculating these amounts.

These assumptions include discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates, mortality rates, among others.

Actual results that differ from the assumptions and changes in assumptions are recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement and affect obligations.

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 other postretirement benefits by applying specific spot rates along the full yield curve to the relevant projected cash flows.

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.

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Net Periodic Benefit Costs (Credits) - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement.

The following table reflects the pre-tax portion of pension and OPEB costs that were charged (credited) to expense, including pension and OPEB mark-to-market adjustments and special termination benefits, in the three years ended December 31, 2024, 2023, and 2022:

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) 2025 2024 2023

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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 2025 pre-tax net periodic expense, including amounts capitalized and the impact of the 2025 lift-out transaction described below (excluding any potential mark-to-market adjustments) to be approximately $29 million based upon the following assumptions:

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

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(1) Assumes a parallel shift in yield curve.

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

Judgment and the use of estimates are required in developing the provision for income taxes, reserve amounts for uncertain tax positions, and reporting of tax-related assets and liabilities such as the interpretation of tax laws and associated regulations.

FirstEnergy is required to make judgments regarding the potential tax effects of various transactions and results of operations in order to estimate its obligations to taxing authorities.

Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken.

FirstEnergy records income taxes in accordance with the liability method of accounting.

See Note 4., "Pension and Other Postemployment Benefits," of the Combined Notes to Financial Statements of the Registrants for additional information.

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.

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Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

FirstEnergy accounts for uncertainty in income taxes in its financial statements using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon settlement.

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.

FirstEnergy recognizes interest expense or income related to uncertain tax positions by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return.

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

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 Notes to Consolidated Financial Statements for a discussion of 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

(In millions) Distribution Transmission Adjustments JCP&L

Revenues $ 2,554 $ 259 $ (175) $ 2,638

Operating Expenses:

Purchased power 1,402 — — 1,402

Other operating expenses 791 64 (175) 680

Provision for depreciation 209 54 — 263

Deferral of regulatory assets, net (134) — — (134)

General taxes 21 2 — 23

Total operating expenses 2,289 120 (175) 2,234

Other Income (Expense):

Miscellaneous income (expense), net 50 (1) — 49

Pension and OPEB mark-to-market adjustment 51 4 — 55

Interest expense - non-affiliates (98) (34) — (132)

Interest expense - affiliates (6) — — (6)

Capitalized financing costs 13 30 — 43

Total other income (expense) 10 (1) — 9

Income taxes 71 36 — 107

Net Income $ 204 $ 102 $ — $ 306

2024 Financial Results (1)

(In millions) Distribution Transmission Adjustments JCP&L

Revenues $ 2,225 $ 242 $ (152) $ 2,315

Operating Expenses:

Purchased power 1,155 — — 1,155

Other operating expenses 745 61 (152) 654

Provision for depreciation 203 46 — 249

Deferral of regulatory assets, net (124) — — (124)

General taxes 20 1 — 21

Total operating expenses 1,999 108 (152) 1,955

Other Income (Expense):

Miscellaneous income (expense), net 44 (10) — 34

Pension and OPEB mark-to-market adjustment 22 2 — 24

Interest expense - non-affiliates (75) (22) — (97)

Interest expense - affiliates (20) — — (20)

Capitalized financing costs 9 19 — 28

Total other expense (20) (11) — (31)

Income taxes 52 35 — 87

Net Income $ 154 $ 88 $ — $ 242

Changes Between 2025 and 2024

Financial Results

Increase (Decrease) Distribution Transmission Adjustments JCP&L

(In millions)

Revenues $ 329 $ 17 $ (23) $ 323

Operating Expenses:

Purchased power 247 — — 247

Other operating expenses 46 3 (23) 26

Provision for depreciation 6 8 — 14

Deferral of regulatory assets, net (10) — — (10)

General taxes 1 1 — 2

Total operating expenses 290 12 (23) 279

Other Income (Expense):

Miscellaneous income (expense), net 6 9 — 15

Pension and OPEB mark-to-market adjustment 29 2 — 31

Interest expense - non-affiliates (23) (12) — (35)

Interest expense - affiliates 14 — — 14

Capitalized financing costs 4 11 — 15

Total other income (expense) 30 10 — 40

Income taxes 19 1 — 20

Net Income $ 50 $ 14 $ — $ 64

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.

The $329 million increase in total revenues resulted from the following sources:

For the Years Ended December 31,

Revenues by Type of Service 2025 2024 Increase / (Decrease)

(In millions)

Distribution services $ 1,150 $ 1,105 $ 45

Generation sales:

Retail 1,380 1,092 288

Wholesale 6 6 —

Total generation sales 1,386 1,098 288

Other 18 22 (4)

Total Revenues $ 2,554 $ 2,225 $ 329

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;

• 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;

• 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.

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.

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.

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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

The information required by Item 7A.

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

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis