REGULATORY MATTERS	9 Months Ended
Sep. 30, 2024
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS STATE REGULATION Each of the Electric Companies retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility. MARYLAND PE operates under MDPSC approved base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The EmPOWER Maryland program previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, in accordance with the MDPSC directive, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million. Hearings were held regarding the revised plan on October 22-24, 2024. An MDPSC order regarding PE’s revised plan remains pending. 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. 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 the law. NEW JERSEY JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third- party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. The base rate increase approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and became effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L was amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery. JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On May 22, 2024, the NJBPU approved JCP&L’s request for a six-month extension of the EE&C Plan I, to December 31, 2024. The budget for the extension period adds approximately $69 million to the original program cost and JCP&L will recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and has a proposed budget of approximately $964 million. EE&C Plan II consists 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. Public hearings were held on June 11, 2024, and the parties are currently engaged in settlement discussions. On July 1, 2024, the NJBPU suspended the procedural schedule. A final NJBPU decision and order was required no later than October 15, 2024, however, the parties submitted a stipulation to extend this deadline to October 31, 2024, which was approved on October 15, 2024. On October 18, 2024, the parties entered into and filed with the NJBPU a stipulation of settlement, wherein the parties agreed to a budget of approximately $817 million for EE&C Plan II, including $784 million of investments that will earn a return on equity of 9.6%, with an equity ratio of 52%, and be recovered over 10 years. The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L and one other party filed comments on July 31, 2023. On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. Orsted’s cancellation does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025. Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the DOE to finance a substantial portion of the project using low-interest rate loans available under the DOE’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024, which was approved on May 17, 2024. The DOE Loan Program Office has initiated a due diligence review of the application, during which period the DOE and JCP&L will continue to negotiate the terms of the loan. On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years. JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition. OHIO The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continued the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with revenue cap increases of $15 million per year through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. Since June 1, 2024, the Ohio Companies have operated under ESP V, as modified by the PUCO, and as further described below. On October 29, 2024, the Ohio Companies filed notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. The Ohio Companies’ application is subject to PUCO review and approval. 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. ESP V, as modified by the PUCO, became effective June 1, 2024 and continues through May 31, 2029, and provides for, among other things, the continuation of existing riders related to purchased power, transmission and uncollectibles, the continuation of the DCR rider with proposed annual revenue cap increases until new base rates are established, the continuation of the AMI rider, and the addition of new riders for storm recovery and vegetation management, with terms and conditions to be established 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, develop an electric vehicle education program to assist customers in transitioning to electric vehicles 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, 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. On June 14, 2024, the Ohio Companies filed an Application for Rehearing seeking greater certainty regarding the key terms of ESP V over the approved term and proposed modifications to the May 15, 2024 order. The Ohio Companies also proposed modifications to ESP V to resolve their Application for Rehearing including, among other things, a reduced three-year ESP V term, approval of certain riders over the full three-year proposed ESP V term, full recovery of investments in the DCR and proposed modifications to preserve the economic value of the order for customers, including a commitment to forego pursuit of the Ohio Companies' request for an enhanced vegetation management program in the 2024 base distribution rate case. Other parties also filed applications for rehearing. As the PUCO did not rule on any applications for rehearing within 30 days of filing, all applications for rehearing were denied by operation of law. 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. The Ohio Companies’ application is subject to PUCO review and approval. The Ohio Companies expect to file an application with the PUCO for ESP VI by early next year in an effort to align with the ongoing base distribution rate case proceedings. On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony. On July 31, 2024, the Ohio Companies filed an update that adjusted the net increase in base distribution revenues to approximately $190 million and incorporated matters in the rate case as directed by the PUCO’s ESP V order. The Ohio Companies would expect to update their application for an increase in base distribution rates after the PUCO issues its order with respect to the Ohio Companies’ withdrawal of ESP V. On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2023, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2024, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2023, which 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 propose that phase two will 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. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 15, 2024, the Ohio Companies filed a motion to consolidate their phase two distribution grid modernization plan proceeding with three audit proceedings pending before the PUCO, which was granted on May 23, 2024. Evidentiary hearings began on June 5, 2024 and concluded on July 2, 2024. On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below. Evidentiary hearings are scheduled to begin February 3, 2025. On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directed the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the DCR rider audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On September 30, 2024, the third-party auditor’s report was filed. The audit examined 53 payments totaling approximately $75 million made in support of the passage of HB 6 and subsequent referendum efforts, and concluded that less than $5 million was allocated to the Ohio Companies. The audit report affirmed the Ohio Companies’ conclusion in its August 6, 2021 filing that a rate impact of less than $15 thousand was charged to the Ohio Companies’ pole attachment customers associated with political and charitable spending in support of HB 6. On October 22, 2024, parties filed comments on the audit report. In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On September 20, 2024, intervenors filed testimony recommending fines for alleged violations of the Ohio corporate separation requirements. Evidentiary hearings were held on October 9 and 10, 2024; the scope of the hearings excluded allegations involving activities related to the passage of HB 6 and the former PUCO chairman, which will be addressed at a later time. To the extent the PUCO ultimately accepts the intervenors’ recommendations and issues a fine to the Ohio Companies, FirstEnergy does not expect any such fine to be material to FirstEnergy. 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 non-regulated competitive employees’ physical space and access to data, updating and implementing a process to annually review the cost allocation manual, developing state specific codes of conduct practices, and implementing additional training related to the cost allocation manual and the state codes of conduct. On October 24, 2024, the administrative law judge issued an entry suspending automatic approval of the amended corporate separation plan and establishing a procedural schedule. In connection with an ongoing annual audit of the Ohio Companies’ DCR rider for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through the DCR rider or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, and further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement. Evidentiary hearings are scheduled to begin February 3, 2025. On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or the now-deceased, former chairman of the PUCO through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered. On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing. As the PUCO did not rule on OCC’s November 17, 2023 application for rehearing within 30 days of filing, the application for rehearing was denied by operation of law. In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO. See Note 10, “Commitments, Guarantees and Contingencies” below for additional details on the government investigations and ongoing litigation surrounding the investigation of HB 6. PENNSYLVANIA The Pennsylvania Companies operated under rates approved by the PPUC, effective as of January 27, 2017. On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have 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. 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. 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 requests 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 reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents 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 include 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 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. The settlement agreement is pending PPUC approval. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is typically updated annually. On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, included the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 was to be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing, neither of which occurred. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024. MP and PE will file their next ENEC filing on or before September 1, 2025. On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024. The first solar generation site went into service in January 2024 and the second solar generation site went into service in September 2024. Construction of the remaining sites are expected to be completed by the end of 2025 at a total investment cost of approximately $110 million. On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE were seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and new depreciation rates became effective on April 1, 2024. On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlements with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset. FERC REGULATORY MATTERS Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo. FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions. Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows. FERC Audit FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $85 million of costs have been recovered as of September 30, 2024. These reclassifications also resulted in a reduction to the Regulated 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 Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Electric Companies are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. On July 5, 2024, the FERC Office of Enforcement issued a set of data requests related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. In addition, on September 26, 2024, the FERC Office of Energy Market Regulation issued data requests to FirstEnergy, which was also related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. 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. In addition, on September 10, 2024, the FERC Office of Enforcement issued a second set of data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy replied. ATSI ROE – Ohio Consumers Counsel v. ATSI, et al. On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact. 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 remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis. Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al. On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.

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.

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

The EmPOWER Maryland program previously required each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. The passage of the Climate Solutions Now Act of 2022 modified the annual incremental energy efficiency targets to 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Additionally at the direction of the MDPSC, PE together with other Maryland utilities were required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, in accordance with the MDPSC directive, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million. Hearings were held regarding the revised plan on October 22-24, 2024. An MDPSC order regarding PE’s revised plan remains pending. 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. 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 the law.

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 has a proposed budget of approximately $964 million. EE&C Plan II consists 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. Public hearings

were held on June 11, 2024, and the parties are currently engaged in settlement discussions. On July 1, 2024, the NJBPU suspended the procedural schedule. A final NJBPU decision and order was required no later than October 15, 2024, however, the parties submitted a stipulation to extend this deadline to October 31, 2024, which was approved on October 15, 2024. On October 18, 2024, the parties entered into and filed with the NJBPU a 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.

On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. Orsted’s cancellation does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.

On November 9, 2023, JCP&L filed a petition for approval of its EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the capital costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. The 2023 base rate case stipulation that was filed on February 2, 2024, necessitated amendments to the EnergizeNJ program. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to remove the high-priority circuits that are to be addressed in the first phase of its reliability improvement plan and to include the second phase of its reliability improvement plan that is expected to further address certain high-priority circuits that require additional upgrades. EnergizeNJ, if approved as amended, will result in the investment of approximately $930.5 million of total estimated costs over five years. JCP&L and various parties are engaged in settlement discussions with respect to the pending EnergizeNJ petition.

The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continued the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with revenue cap increases of $15 million per year through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. Since June 1, 2024, the Ohio Companies have operated under ESP V, as modified by the PUCO, and as further described below. On October 29, 2024, the Ohio Companies filed notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. The Ohio Companies’ application is subject to PUCO review and approval.

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. ESP V, as modified by the PUCO, became effective June 1, 2024 and continues through May 31, 2029, and provides for, among other things, the continuation of existing riders related to purchased power, transmission and uncollectibles, the continuation of the DCR rider with proposed annual revenue cap increases until new base rates are established, the continuation of the AMI rider, and the addition of new riders for storm recovery and vegetation management, with terms and conditions to be established 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, develop an electric vehicle education program to assist customers in transitioning to electric vehicles 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, 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. On June 14, 2024, the Ohio Companies filed an Application for Rehearing seeking greater certainty regarding the key terms of ESP V over the approved term and proposed modifications to the May 15, 2024 order. The Ohio Companies also proposed modifications to ESP V to resolve their Application for Rehearing including, among other things, a reduced three-year ESP V term, approval of certain riders over the full three-year proposed ESP V term, full recovery of investments in the DCR and proposed modifications to preserve the economic value of the order for customers, including a commitment to forego pursuit of the Ohio Companies' request for an enhanced vegetation management program in the 2024 base distribution rate case. Other parties also filed applications for rehearing. As the PUCO did not rule on any applications for rehearing within 30 days of filing, all applications for rehearing were denied by operation of law. 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. The Ohio Companies’ application is subject to PUCO review and approval. The Ohio Companies expect to file an application with the PUCO for ESP VI by early next year in an effort to align with the ongoing base distribution rate case proceedings.

On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. The Ohio Companies requested a net increase in base distribution revenues of approximately $94 million with a return on equity of 10.8% and capital structures of 44% debt and 56% equity for CEI, 46% debt and 54% equity for OE, and 45% debt and 55% equity for TE, which reflects a roll-in of current riders such as DCR and AMI. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, the Ohio Companies request recovery of certain incurred costs, including the impact of major storms, a program to convert streetlights to LEDs, and others. On June 14, 2024, the Ohio Companies filed supporting testimony. On July 31, 2024, the Ohio Companies filed an update that adjusted the net increase in base distribution revenues to approximately $190 million and incorporated matters in the rate case as directed by the PUCO’s ESP V order. The Ohio Companies would expect to update their application for an increase in base distribution rates after the PUCO issues its order with respect to the Ohio Companies’ withdrawal of ESP V.

On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2023, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 15, 2024, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2023, which 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 propose that phase two will 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. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 15, 2024, the Ohio Companies filed a motion to consolidate their phase two distribution grid modernization plan proceeding with three audit proceedings pending before the PUCO, which was granted on May 23, 2024. Evidentiary hearings began on June 5, 2024 and concluded on July 2, 2024.

activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded DCR rider audit proceeding described below. Evidentiary hearings are scheduled to begin February 3, 2025.

On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directed the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the DCR rider audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On September 30, 2024, the third-party auditor’s report was filed. The audit examined 53 payments totaling approximately $75 million made in support of the passage of HB 6 and subsequent referendum efforts, and concluded that less than $5 million was allocated to the Ohio Companies. The audit report affirmed the Ohio Companies’ conclusion in its August 6, 2021 filing that a rate impact of less than $15 thousand was charged to the Ohio Companies’ pole attachment customers associated with political and charitable spending in support of HB 6. On October 22, 2024, parties filed comments on the audit report.

In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On September 20, 2024, intervenors filed testimony recommending fines for alleged violations of the Ohio corporate separation requirements. Evidentiary hearings were held on October 9 and 10, 2024; the scope of the hearings excluded allegations involving activities related to the passage of HB 6 and the former PUCO chairman, which will be addressed at a later time. To the extent the PUCO ultimately accepts the intervenors’ recommendations and issues a fine to the Ohio Companies, FirstEnergy does not expect any such fine to be material to FirstEnergy.

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 non-regulated competitive employees’ physical space and access to data, updating and implementing a process to annually review the cost allocation manual, developing state specific codes of conduct practices, and implementing additional training related to the cost allocation manual and the state codes of conduct. On October 24, 2024, the administrative law judge issued an entry suspending automatic approval of the amended corporate separation plan and establishing a procedural schedule.

In connection with an ongoing annual audit of the Ohio Companies’ DCR rider for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through the DCR rider or

through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, and further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement. Evidentiary hearings are scheduled to begin February 3, 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.

The Pennsylvania Companies operated under rates approved by the PPUC, effective as of January 27, 2017. On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have 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.

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.

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 requests 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 reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents 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 include 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 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. The settlement agreement is pending PPUC approval. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025.

On August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represented a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, included the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 was to be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provided for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $184 million to be recovered from 2025 through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover by more than $50 million from January through June 2024 and a party elects to invoke a case filing, neither of which occurred. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024. MP and PE will file their next ENEC filing on or before September 1, 2025.

On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. On April 24, 2023, MP and PE sought approval for surcharge cost recovery from the WVPSC for three of the five solar sites, representing 30 MWs of generation. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024. The first solar generation site went into service in January 2024 and the second solar generation site went into service in September 2024. Construction of the remaining sites are expected to be completed by the end of 2025 at a total investment cost of approximately $110 million.

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.

refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase included the approximate $75 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense, but deferred issues related to a change in the net energy metering credit. Additionally, the settlement included a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recovery (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlements with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.

Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.

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

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

FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to

operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $85 million of costs have been recovered as of September 30, 2024. These reclassifications also resulted in a reduction to the Regulated 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 Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Electric Companies are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania.

On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. On July 5, 2024, the FERC Office of Enforcement issued a set of data requests related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. In addition, on September 26, 2024, the FERC Office of Energy Market Regulation issued data requests to FirstEnergy, which was also related to the 2022 reclassification of operating expenses, to which FirstEnergy replied. 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. In addition, on September 10, 2024, the FERC Office of Enforcement issued a second set of data requests related to the classification and recovery of a since terminated fuel consulting contract, to which FirstEnergy replied.

On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.

A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 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.

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