FIRSTENERGY CORP

9. REGULATORY MATTERS

The disclosures in this note apply to FirstEnergy.

Disclosures under “State Regulation,” “Pennsylvania,” “FERC Regulatory Matters,” “Transmission ROE Incentive,” “Transmission ROE Methodology,” “Transmission Planning Supplemental Projects,” “Local Transmission Planning Complaint,” “PJM Capacity Market Reforms,” and “Large Load Interconnection Rulemaking” are applicable to FE PA.

Disclosures under “State Regulation,” “New Jersey,” “FERC Regulatory Matters,” “Transmission ROE Incentive,” “Transmission ROE Methodology,” “Transmission Planning Supplemental Projects,” “Local Transmission Planning Complaint,” “PJM Capacity Market Reforms,” and “Large Load Interconnection Rulemaking” are applicable to JCP&L.

STATE REGULATION

Each of the Electric Companies’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

MARYLAND

PE operates under MDPSC-approved distribution base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.

The EmPOWER Maryland program requires electric utilities to achieve specified energy efficiency and greenhouse gas reduction targets, which were modified by the Utility RELIEF Act to reduce certain targets for the 2027-2035 program cycles. PE's revised 2024-2026 EmPOWER plan, with a budget of approximately $314 million, was approved by the MDPSC in December 2024. PE filed its proposed 2027-2029 plan in September 2026. Beginning in 2026, PE is required to expense 100% of EmPOWER program costs as incurred, with previously deferred balances to be recovered through 2030. Legislation effective July 1, 2024 reduced the carrying costs recoverable on unamortized EmPOWER balances. PE challenged the legislation, and in August 2025 the Circuit Court for Washington County, Maryland ruled in PE's favor. The MDPSC and MDOPC appealed the decision, and oral argument before the Appellate Court of Maryland was held on September 4, 2026.

On September 1, 2026, PE filed its proposed large load tariff which would create a separate class of large load customers thereby insulating residential customers from bearing costs associated with the interconnection of large load customers to the electric system.

On September 4, 2026, PE filed with the MDPSC a distribution base rate case seeking to, among other things, increase PE’s Maryland annual base rate distribution revenues by approximately $53 million and approve a proposed three-year program focused on improving reliability. The case uses a historic test year of twelve months ending March 31, 2026, and requested an ROE of 10.6% and capital structure of approximately 54% equity and 46% debt. Evidentiary hearings are scheduled to begin January 11, 2027. A final order and new rates are expected to become effective in the second quarter of 2027.

NEW JERSEY

JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

In 2021, JCP&L, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US LLC and EDF Renewables North America, proposed transmission upgrades to connect offshore wind-generated electricity to the New Jersey power grid. The NJBPU approved portions of the proposal on October 26, 2022, authorizing approximately $723 million of transmission investments and providing JCP&L the option to acquire up to a 20% equity interest in Mid-Atlantic Offshore Development, LLC. On August 22, 2023, FERC approved an abandonment incentive that allowed recovery of certain prudently incurred project costs if the project were cancelled for reasons beyond JCP&L’s control.

Beginning in late 2023, major offshore wind developments in New Jersey were cancelled or abandoned. In response to these developments, JCP&L sought guidance from the NJBPU in 2025 regarding project scheduling while continuing to meet its contractual obligations. In August 2025, the NJBPU directed JCP&L to defer certain transmission investments for approximately 2.5 years and directed JCP&L to 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. Capital investments in the transmission projects totaled approximately $167 million as of September 30, 2026.

On April 22, 2026, the NJBPU issued an order finding that, among other things, continued investment in certain of the transmission infrastructure to connect offshore wind generated electricity to the grid is not in the best interest of the state or its ratepayers. In the order, the NJBPU authorized execution of an agreement with PJM to terminate the identified transmission projects, which it filed at FERC on April 23, 2026. The agreement included provisions to the effect that New Jersey’s ratepayers will remain responsible for JCP&L’s prudently incurred costs for the affected projects and a request for approval by June 23, 2026. On May 14, 2026, JCP&L filed supportive comments at FERC. On June 22, 2026, FERC accepted the termination agreement. On July 2, 2026, PJM notified JCP&L that PJM had terminated the agreements that obligated JCP&L to construct the identified projects. JCP&L expects to file an application for FERC authorization to recover the abandoned project costs.

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 provided residential customers with a $30 bill credit in July and August 2025, with JCP&L deferring the cost as a regulatory asset and recovering the amount through customer bill charges from September 2025 through February 2026; the regulatory asset has since been fully recovered.

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. On April 13, 2026, NJBPU staff issued a letter to JCP&L stating its intention to recommend that the NJBPU impose a penalty against JCP&L in the amount of $44 million, while also requesting a meeting with JCP&L to discuss the potential penalty recommendation and a possible resolution. On April 16, 2026, JCP&L responded in writing to the NJBPU staff welcoming the opportunity to discuss with NJBPU staff and disputing the magnitude of the recommended penalty and questioning the approach taken by NJBPU staff. JCP&L is engaged in settlement discussions with the parties and had a meeting with the NJBPU staff on July 17, 2026. A pre-hearing conference has been scheduled for October 29, 2026. JCP&L believes it is probable that it will incur a loss, but based on the status of the settlement discussions is unable to estimate the amount of any penalty and/or predict other actions that may be imposed by the NJBPU. On October 20, 2026, the NJBPU opened a new docket to review JCP&L’s attainment of the NJBPU’s minimum reliability levels for calendar year 2025.

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 EE&C Plan during the one-year period from July 1, 2023, through June 30, 2024. The modification was effective February 1, 2026.

On May 21, 2026, the NJBPU issued an order concluding that certain nuclear generating units participating in the state’s ZEC program received duplicate compensation during 2024, and directed the owners of the affected generating units to refund the duplicate payments, with applicable interest, to the affected EDCs, including JCP&L. The order further directed that the refunded amounts be returned to customers through reinstated ZEC tariffs beginning June 1, 2026. On May 26, 2026, JCP&L received payment in the amount of $82 million. Also on May 26, 2026, JCP&L made the requisite compliance filing with the NJBPU requesting restoration of its ZEC tariff effective June 1, 2026, and began issuing customer refunds. Refunds are expected to continue through May 31, 2027, or until such time as the refunded balance is exhausted. As of September 30, 2026, JCP&L's regulatory liability associated with these amounts to be refunded to customers was approximately $56 million.

On July 15, 2026, the NJBPU issued an order directing a one-year transition period beginning on July 1, 2027, and ending on June 30, 2028, after which New Jersey EDCs would begin a full six-year cycle of energy efficiency programs. JCP&L’s EE&C Plan II ends on June 30, 2027. In accordance with the order, JCP&L filed its proposed transition plan with the NJBPU on September 30, 2026, which seeks to continue JCP&L’s existing cost recovery and lost revenue recovery mechanisms and contemplates a lower ROE for JCP&L’s energy efficiency programs by 150 basis points, at a proposed budget of approximately $178 million. The matter is pending before the NJBPU.

On August 6, 2026, JCP&L filed with the NJBPU a base rate case utilizing a historical test period for the 12 months ending June 30, 2026. JCP&L proposed a net increase in base distribution revenues of approximately $253 million, with an ROE of 10.2% and a capital structure of approximately 47% debt and approximately 53% equity, with an effective date of May 6, 2027. JCP&L has also proposed to offset the increase in rates for residential customers until January 1, 2028, through a new, temporary tax-adjustment rider and amortization of an existing regulatory liability during this period. The filing also proposes a new storm recovery charge rider and requests additional funding for enhanced storm response and expanded vegetation management. The NJBPU has referred the matter to the New Jersey Office of Administrative Law and discovery has begun.

OHIO

The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. From June 1, 2024, until January 31, 2025, the Ohio Companies operated under ESP V, as modified by the PUCO, and as further described below. On December 18, 2024, the PUCO approved the Ohio Companies’ notice to withdraw ESP V and approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. ESP IV, as modified, continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with an annual revenue cap of $390 million. In addition, ESP IV, as modified, includes a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and contributions, totaling $6.39 million per year, to: (a) fund energy conservation, economic development and job retention programs in the Ohio Companies’ service territories; and (b) establish fuel-funds in each of the Ohio Companies’ service territories to assist low-income customers.

On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which became effective June 1, 2024, and would have continued through May 31, 2029. The Ohio Companies filed an application for rehearing challenging various aspects of the May 15, 2024, order, but due to the risks and uncertainty resulting from the Ohio Companies’ application for rehearing being denied by operation of law, on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. On December 18, 2024, the PUCO approved the Ohio Companies’ notice of withdrawal. Also on December 18, 2024, the PUCO approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. Consistent with ESP IV, the PUCO authorized the Ohio Companies’ reinstatement of the DCR rider. Additionally, the PUCO ordered that storm costs deferred under ESP V since June 1, 2024, remain on the Ohio Companies’ books and subject to review in a future case. On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV. On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV. On May 22, 2025, the Supreme Court of Ohio granted the Ohio Companies’ motion to intervene in the appeal. On July 7, 2025, OCC and NOAC filed their Appellants’ brief. Appellees, including the PUCO and the Ohio Companies, filed their briefs on August 26, 2025, to which OCC and NOAC replied on September 15, 2025.

On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI. 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. 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 an ROE of 9.63% and a hypothetical capital structure of 48.8% debt and 51.2% equity for all three Ohio Companies, which reflects a roll-in of current riders such as DCR and AMI. The PUCO authorized continuance of Rider DCR with a cap increase commensurate with capital investments through January 31, 2025, and approved the Ohio Companies’ proposal to change pension and OPEB recovery to the delayed recognition method. Additionally, the order authorizes recovery of certain deferred costs for storm restoration, operations and maintenance, and energy efficiency programs. As a result of the order, the Ohio Companies recognized a $352 million pre-tax impairment charge related to future recovery disallowances of certain previously capitalized amounts. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025, base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On February 18, 2026, the PUCO issued an entry on rehearing, which extended the amortization period for recovery of deferred storm restoration costs from five years to twenty-five years, subject to prudency review, and clarified the amount of the authorized increase in Rider DCR revenue caps is $14 million, subject to the Ohio Companies meeting reliability standards. With these adjustments, the rate case’s outcome is a net decrease in base distribution revenues of the Ohio Companies of approximately $5 million. The entry further ordered the Ohio Companies to file revised final tariffs and approved the Ohio

Companies’ compliance tariffs, effective March 1, 2026. On March 20, 2026, the Ohio Companies and certain other parties filed with the PUCO second applications for rehearing of the February 18, 2026, entry on rehearing. On April 14, 2026, the PUCO issued an entry on rehearing denying all applications for rehearing. On May 14, 2026, Retail Energy Supply Association and IGS Energy Supply, LLC jointly filed with the PUCO a request for clarification and application for rehearing, to which the OCC and the Ohio Companies responded on May 26, 2026. On June 10, 2026, the PUCO issued its Fourth Entry on Rehearing, denying the application for rehearing. On August 10, 2026, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, appealing the PUCO’s actions on rehearing, including the extension of the Ohio Companies’ deferred storm cost amortization period, and the issuance of additional directives on rehearing without following procedural rules. On October 19, 2026, the Ohio Companies filed their initial brief.

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. On May 11, 2026, the Attorney Examiner issued an entry consolidating the SEET proceedings for calendar years 2021 through 2024. On July 21, 2026, the Ohio Companies and the PUCO staff entered into a settlement, unopposed by OCC, stipulating that the Ohio Companies did not have significantly excessive earnings in 2021, 2022, 2023 or 2024. An evidentiary hearing was held on August 11, 2026.

On January 7, 2026, the PUCO issued an order, which directed the Ohio Companies to pay their customers, among other things, restitution and refunds totaling approximately $275 million ($213 million after-tax), which was recognized in the fourth quarter of 2025. The restitution and refunds are being provided to customers over three billing cycles, which began in February 2026. As of September 30, 2026, the Ohio Companies have issued approximately $266 million in restitution and refunds.

On May 22, 2026, the Ohio Companies filed with the PUCO a three-year rate plan, requesting approval of three consecutive, annual test periods that begin July 1, 2027 and end June 30, 2030. The application proposes a net increase in the Ohio Companies’ base distribution revenues of approximately $254 million in the first year, approximately $59 million in the second year, and approximately $80 million in the third year, with an ROE of 10.2% and a capital structure of approximately 47% debt and approximately 53% equity for all three Ohio Companies. On June 12, 2026, PUCO staff issued a deficiency letter requesting additional supplementation in certain areas, which the Ohio Companies provided on June 22, 2026. On July 1, 2026, an administrative law judge deemed the application complete and set a procedural schedule. Evidentiary hearings are set to begin March 1, 2027.

On June 12, 2026, at the PUCO’s direction, the Ohio Companies filed an application requesting approval of a proposed data center tariff which will create a separate class for data centers and ensure proper allocation of costs associated with the interconnection of large load customers to the electric system. Comments and reply comments on the proposed data center tariff were filed by various parties in August 2026.

See Note 10., “Commitments, Guarantees and Contingencies” of the Combined Notes to Financial Statements of the Registrants below for additional details on the ongoing government investigations and ongoing litigation surrounding HB 6.

PENNSYLVANIA

FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025. FE PA operates under rates approved by the PPUC, effective as of January 1, 2025. FE PA operates under a DSP through the May 31, 2027 delivery period, which provides for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. In December 2024, the PPUC approved FE PA’s LTIIP III program, which contemplates an approximately $1.4 billion investment plan from 2025 through 2029 and the eligible costs of which are recoverable through FE PA’s distribution system improvement charge. FE PA may increase its LTIIP investment plan up to 20% without seeking additional PPUC approval.

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021, through May 31, 2026, was approved by the PPUC on June 18, 2020, providing cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.

On November 26, 2025, FE PA submitted a petition for approval of its Phase V EE&C 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 reached a full settlement in principle and filed with the PPUC a Joint Petition for Complete Settlement on February 19, 2026. On March 12, 2026, the PPUC issued an order approving the settlement with limited modifications requiring FE PA to file revisions to the plan, which were filed on April 15, 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 this 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 hearing was held on June 15, 2026. FE PA reached a comprehensive settlement with certain parties, which was filed with the PPUC on July 2, 2026. On August 21, 2026, the administrative law judges issued a decision recommending that the PPUC approve, without modification, the July 2, 2026, settlement agreement. On October 26, 2026, the PPUC issued an order approving the settlement agreement with one modification that opens a new statewide proceeding to be instituted and conducted by June 1, 2027, associated with certain customer shopping protections.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective March 27, 2024, and, for applicable customers, a WVPSC-approved solar surcharge that was most recently adjusted effective January 15, 2026. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually and MP and PE filed their ENEC filing on August 29, 2025, for rates effective January 1, 2026. During the first quarter of 2026, MP and PE incurred significant PJM charges during the Winter Storm Fern weather event totaling $145 million, which were deferred for future recovery as part of the ENEC.

On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. Two of the five solar generation sites went into service in 2024, with the third in April 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. The WVPSC issued an order on March 26, 2026, approving the MP and PE vegetation management program and granting rate recovery for its costs.

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 May 6, 2026, an evidentiary hearing was held. In an order dated August 28, 2026, the WVPSC instructed MP and PE to submit additional information by December 1, 2026 and further set the filing of the next integrated resource plan for December 1, 2028.

On February 13, 2026, MP and PE filed a CPCN to construct and operate the 1,200 MW combined cycle gas turbine plant, that will be known as Maidsville Energy Center, and the 70 MWs of solar generation capacity, each referenced in their integrated resource plan above, 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. Evidentiary hearings were held on July 16 and 17, 2026. A final order is expected from the WVPSC in the fourth quarter of 2026.

To support the proposed Maidsville Energy Center project schedule, FirstEnergy has entered into a reservation agreement with Siemens Energy, Inc. for turbines scheduled for delivery in 2030. As described in the CPCN case, any contemplated data center agreements utilizing the Maidsville Energy Center's output, would be expected to address customer protections, pricing, risk transfer and long-term benefit sharing for existing West Virginia customers.

On May 15, 2026, MP and PE filed a base rate proceeding proposing an increase in electric rates of $188.4 million, an approximate 10.6% increase in total revenues. The filing includes a base rate increase of $174.6 million and a proposed reliability program and surcharge of $13.8 million. As an alternative, MP and PE requested a phased approach of two increases of $37.9 million effective August 1, 2026, and $37.6 million effective June 1, 2027, with a commitment to abstain from filing another base rate case until April 1, 2028. On June 11, 2026, the WVPSC staff filed a motion to dismiss, which the WVPSC denied on July 2, 2026. The WVPSC held a hearing on the alternative two-phase approach on July 9, 2026. On July 31, 2026, the WVPSC issued an order approving the alternative two-phase approach without modification. New rates associated with the first phase became effective on August 1, 2026. The matter was appealed to the Supreme Court of Appeals of West Virginia on August 31, 2026, and remains pending before the court. MP and PE cannot predict the outcome of this appeal.

FERC REGULATORY MATTERS

Under the FPA, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM, and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although, in the case of the Electric Companies, major wholesale purchases remain subject to review and regulation by the relevant state commissions. The Electric Companies and AE Supply are required to renew their respective authorizations every three years, and on December 16, 2025, the companies filed applications for the next renewal period.

Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

FirstEnergy believes that it is in material compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.

Transmission ROE Incentive

On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliate and American Electric Power Service Corporation, and Duke Energy Ohio, Inc. asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contended that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke Energy Ohio, Inc., but granted it as to AEP’s Ohio affiliate. AEP’s Ohio affiliate and OCC appealed FERC’s orders to the Sixth Circuit. On January 17, 2025, the Sixth Circuit ruled that the 50 basis point adder is available only where RTO membership is voluntary, that Ohio law requires Ohio’s transmission utilities to be members of an RTO, and that it was unlawful for FERC to excise the adder from AEP’s Ohio affiliate rates, but not from the Duke Energy Ohio, Inc. and ATSI rates. During 2024, as a result of the ruling, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the FirstEnergy Consolidated Statements of Income and Comprehensive 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. On June 25, 2026, FERC issued an order on remand directing ATSI to submit a compliance filing within 30 days to remove the RTO incentive and make refunds with interest within 30 days for the period beginning February 24, 2022, through the date of the refund. On July 22, 2026, FERC approved ATSI’s subsequent request to defer the deadline to issue refunds until February 28, 2027, in order to accommodate the PJM and MISO processes for processing refunds as directed by FERC’s order. On July 27, 2026, ATSI submitted to FERC a filing to amend its formula rate to remove on a going-forward basis 50 basis points of authorized earnings in compliance with FERC’s orders. FirstEnergy also filed a request for rehearing on July 27, 2026, arguing that the Federal Power Act limited the refund period to 15 months. On August 27, 2026, FERC denied the request for rehearing by operation of law. On October 21, 2026, ATSI appealed FERC’s June 25, 2026, order to the Sixth Circuit. As of September 30, 2026, ATSI’s estimated refund obligation, including interest, totaled approximately $51 million, which is recorded in “Regulatory liabilities” on FirstEnergy’s Consolidated Balance Sheets.

Transmission ROE Methodology

A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 and remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis; provided however, due to the Sixth Circuit’s ruling in the Transmission ROE Incentive matter described above, ATSI revised the ROE in its transmission rates effective August 1, 2026.

Transmission Planning Supplemental Projects

On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. Subsequently, intervenors expanded the scope of this proceeding to all of the transmission utilities in the PJM market, including JCP&L. ATSI and the other transmission utilities in Ohio and in the PJM market filed comments. The matter is pending before FERC.

Local Transmission Planning Complaint

On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates. The complaint demands that FERC: (i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100 kV or higher; (ii) appoint “independent transmission monitors” to conduct such planning; and (iii) condition construction of local transmission facilities on the facility having been planned by the “independent transmission monitor.” FirstEnergy is participating in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. FirstEnergy, together with the PJM transmission owners, filed a motion to dismiss the complaint on March 20, 2025, which is pending before FERC. FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy and its transmission capital investment strategy.

Ghiorzi v. PJM

In December 2023, PJM assigned certain baseline RTEP projects to NextEra Energy Transmission, which subsequently informed PJM that it would not construct the projects. On April 3, 2025, following the reassignment by PJM of certain baseline RTEP projects in Maryland and Virginia to PE, two individuals filed a complaint at FERC challenging this outcome, which FERC denied on February 2, 2026. The complainants asserted that PJM erred in reassigning the work to PE because such reassignment projects: (i) did not reflect the cost estimates or cost caps included in NextEra Energy Transmission’s bid; and (ii) would be constructed with different routing than originally proposed. On February 2, 2026, FERC denied the complaint and on April 3, 2026, FERC denied the rehearing request filed by the complainants on March 4, 2026. On June 22, 2026, FERC affirmed its February 2, 2026, order denying the complaint. The deadline to appeal has passed and FERC’s order is final.

Abandonment Transmission Rate Incentive

On February 26, 2025, PJM completed its 2024 RTEP Open Window 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. On July 27, 2026, the PJM Board of Managers announced its plans to procure up to 6,800 MWs of capacity resources, the costs of which would be allocated to load-serving entities. On July 31, 2026, PJM filed its proposed reliability backstop procurement set of tariff amendments at FERC, which proposal called for PJM to procure 6,800 MWs of new capacity resources in the fourth quarter of 2026 and calls for the costs of the procurement to be charged to load-serving entities. PJM’s proposal also provides that, if a transmission owner exits PJM, at and after such exit, the costs are to be charged to the transmission owner. On August 21, 2026, FirstEnergy filed protests at FERC arguing, among other things, that PJM had failed to demonstrate that the proposal to charge the costs to exiting transmission owners is “just and reasonable” as required by the Federal Power Act. On September 29, 2026, FERC issued an order suspending PJM’s proposed reliability backstop procurement tariff amendments until February 28, 2027, and instituting further proceedings. FERC further invited PJM to submit a second set of tariff amendments to address the issues that were identified in the September 29, 2026, order. On September 30, 2026, PJM announced the procurement would not begin as previously scheduled. FirstEnergy expects it will continue to participate in the PJM stakeholder processes and FERC proceedings.

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 AI data centers and “hybrid” data center/electric generation facilities. The U.S. Secretary of Energy 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. The U.S. Secretary of Energy requested that FERC take final action by April 30, 2026. On October 27, 2025, FERC noticed the U.S. Secretary of Energy’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 June 18, 2026, FERC established a “show cause” proceeding for PJM and the PJM transmission owners, while also establishing similar dockets for each of the other RTOs and ISOs and their respective transmission owners. FERC is using the “show cause” proceeding as a means for the affected transmission owners to submit tariff revisions to address the requirements needed to interconnect and serve customers seeking transmission service on behalf of large loads. On July 28, 2026, PJM filed a motion with FERC advising of its plans to submit the compliance filing in mid-November 2026, which FERC accepted on August 14, 2026. On August 17, 2026, the PJM transmission owners filed a partial compliance filing to set a rate for interim network integration transmission service. On September 22, 2026, FERC issued an order dismissing all requests for rehearing and clarified that the June 18, 2026, order made no final determination and that the matter is in abeyance pending submission of the compliance filing. FirstEnergy is unable to predict the outcome of this proceeding.

Utility RELIEF Act and Related FERC Complaint

The Utility RELIEF Act, which became effective July 1, 2026, requires all transmission utilities within Maryland to participate as members in an RTO. On July 2, 2026, the Maryland Energy Administration, MDOPC, and MDPSC filed a complaint at FERC against PE, Valley Link Maryland, and all other Maryland transmission owners. The complaint seeks a FERC order directing the Maryland transmission owners to remove the RTO 50 bps ROE adder incentive from each of their transmission rates. The Maryland Energy Administration, MDOPC, and MDPSC seek to apply FERC’s rulings that remove the RTO incentive from transmission rates when state laws require RTO participation. The complaint requested that any RTO incentive adders collected after July 1, 2026, be refunded. On August 5, 2026, PE and its affiliate, Valley Link Maryland, each responded to the complaint. The Maryland Energy Administration, MDOPC, and MDPSC filed a response on September 3, 2026, to which PE and Valley Link Maryland each responded on September 18, 2026. The Maryland Energy Administration, MDOPC, and MDPSC filed a response on October 5, 2026, to which PE responded on October 20, 2026.

PJM Interim Resource Adequacy Service

On August 13, 2026, PJM filed with FERC its interim resource adequacy service proposal, which would permit curtailment to data centers that did not bring their own supply of new generation resources. On September 3, 2026, FirstEnergy filed a limited protest of certain elements of PJM’s filing. On October 12, 2026, FERC issued an order accepting PJM’s proposed large load definition and PJM’s proposal to establish a registry to log and track such large loads. FERC rejected all of the remaining elements of PJM’s proposal without prejudice.

Winter Storm Fern

On October 6, 2026, MP filed a complaint at FERC against PJM alleging that PJM’s Day-Ahead Market dispatch order during Winter Storm Fern in January and February 2026 was not consistent with the PJM Tariff and resulted in approximately $145 million in Winter Storm Fern-related net wholesale power costs being incurred by MP, which otherwise would be recovered from MP’s and PE’s West Virginia retail customers through the ENEC. On October 26, 2026, PJM filed its answer to MP’s complaint and a motion to dismiss. The matter is pending before FERC.