FE

FIRSTENERGY CORP. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-Q discusses the three and six months ended June 30, 2026, and year-over-year comparisons between the three and six months ended June 30, 2026, and 2025, and should be read in conjunction with the Registrants’ interim financial statements and notes included in this Form 10-Q, and the Registrants’ audited financial statements, notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7. in its Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on February 18, 2026. EXECUTIVE SUMMARY AND RECENT DEVELOPMENTS Company Overview FirstEnergy is dedicated to integrity, safety, reliability and operational excellence and is principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission. Its electric distribution companies form one of the nation's largest investor-owned electric systems, serving over 6 million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. FirstEnergy’s transmission subsidiaries operate more than 24,000 miles of transmission lines that connect the Midwest and Mid-Atlantic regions and two regional transmission operation centers. As of June 30, 2026, AGC and MP control 3,610 MWs of net maximum generation capacity. Segment Overview See Note 11., “Segment Information,” of the Combined Notes to Financial Statements of the Registrants. Investment Strategy FirstEnergy invests in both its regulated operations to improve reliability and the customer experience, and its people to attract, retain and develop talented and engaged employees to carry out its strategy. FirstEnergy’s customer-focused Energize365 investment plan for the 2026 to 2030 time period is $36 billion, approximately 25% higher than the previous 2025 to 2029 five-year plan, and aims to strengthen the grid, improve reliability and support growing customer demand. Through the Energize365 program, system-wide capital investments from 2026 to 2030 are expected to include 28% in the Distribution segment, 35% in the Integrated segment, and 35% in the Stand-Alone Transmission segment, focused on the following: •Distribution and Transmission investments to enhance grid reliability and resiliency and support growing customer demand, including through: •Programs to drive system resiliency through automation technology and communication, including the Ohio Companies’ distribution grid modernization plans, Pennsylvania's LTIIP, New Jersey's EnergizeNJ, and implementing advanced metering infrastructure; •Operational flexibility projects that are expected to build capacity and support the evolving grid such as projects to support increased data center load; •Enhancing system performance by implementing new designs and technologies to reduce load at risk; •Upgrading system conditions that enhance reliability; and •Transmission projects awarded through the PJM Open Window to address regional expansion projects, including incremental opportunities in the 2026 Open Window, for which the planning period was opened. •Base distribution projects to address aging infrastructure. •Generation maintenance projects that maintain operations of fossil electric generation facilities and remain compliant with environmental regulations through the end of their useful life. FirstEnergy believes there is a continued long-term pipeline of investment opportunities for its existing distribution and transmission infrastructure beyond those opportunities identified through 2030, which are expected to strengthen the grid and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. Finance FirstEnergy aims to execute its Energize365 investment plan through a strengthened financial position. Energize365 capital investments included in the current five-year plan are expected to be funded with a combination of organic cash flows and the issuance of debt, including hybrid securities. Additionally, FirstEnergy may issue its common equity to fund capital expenditures in its 2026 through 2030 planning period averaging approximately 1% of its now current market capitalization in each year of the 46 planning period, subject to market conditions and other factors. FirstEnergy believes it has optimized its financing plan to retain flexibility in an uncertain interest rate environment. On March 30, 2026, Moody’s revised FE’s outlook to positive from stable. Moody’s also affirmed FE’s ratings, including its Baa3 Issuer and senior unsecured ratings. Dividend Growth FirstEnergy continues to return value to shareholders. In February 2026, the FE Board declared a $0.02 per share increase to the quarterly cash common stock dividend to $0.465 per share payable June 1, 2026, which represents a 4.5% increase compared to dividends declared in 2025. Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings, cash flows, credit metrics and general economic and other business conditions. PJM RTEP Open Window Projects On February 21, 2025, FET, DominionHV and Transource entered into the Valley Link Operating Agreement, which established the general framework for Valley Link and the Valley Link Subsidiaries to accept, design, develop, construct, own, operate and finance those transmission projects awarded by PJM to Valley Link. This general framework includes parameters regarding the relationship among the three members, confers governance rights to its members so long as certain ownership percentages are maintained, as described below, and defines the list of projects that Valley Link will have the right to develop. Valley Link is the owner of the Valley Link Subsidiaries, which are organized in various states. On February 26, 2025, in response to the PJM 2024 RTEP Open Window #1, PJM awarded two electric transmission projects to Valley Link estimated to be approximately $3 billion, with FET’s share estimated to be approximately $1 billion. On February 13, 2026, FET and Transource entered into the Grid Growth Operating Agreement, which established the general framework for Grid Growth to accept, design, develop, construct, own, operate and finance certain transmission projects awarded by PJM to certain of the subsidiaries of Grid Growth. This general framework includes parameters regarding the relationship between the two members, confers governance rights to its members so long as certain ownership percentages are maintained and defines the list of projects that Grid Growth will have the right to develop. The relative ownership interests of the members under the Grid Growth Operating Agreement are 50% for each of FET and Transource. Grid Growth is the sole owner of Grid Growth Ohio and owns an 80% interest in Grid Growth EHV, with Transource owning the remaining interest. On February 12, 2026, in response to the PJM 2025 RTEP Open Window #1, PJM awarded a project to Grid Growth estimated to be approximately $1 billion, with FET’s share estimated to be approximately $448 million. Regulatory Matters - Ohio On April 5, 2023, the Ohio Companies sought approval from the PUCO for their ESP V. The proposed plan would maintain an eight-year term beginning June 1, 2024, and continue riders recovering costs associated with distribution infrastructure investments and approved grid modernization investments. ESP V additionally proposed new riders that would support reliability, and included provisions supporting affordability and enhancing the customer experience. As more fully described in “Outlook - State Regulation - Ohio,” in Item 2., "Management's Discussion and Analysis of Financial Condition and Results of Operations," on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV, which was approved by the PUCO on December 18, 2024. On January 22, 2025, the PUCO approved the Ohio Companies’ ESP IV compliance tariffs with an effective date of February 1, 2025, at which point the Ohio Companies resumed operating under ESP IV with certain modifications, as described in “Outlook - State Regulation - Ohio,” in Item 2., "Management's Discussion and Analysis of Financial Condition and Results of Operations". The Ohio Companies’ return to ESP IV was appealed by certain intervenors and the matter remains pending before the Supreme Court of Ohio. On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. On January 27, 2025, the Ohio Companies notified the PUCO of their intention to update their application for an increase in base distribution rates to remove ESP V related provisions from the base rate case. On November 19, 2025, the PUCO issued an order in the rate case. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025, base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On January 9, 2026, the Ohio Companies filed an expedited motion for ruling on the proposed compliance tariffs and on February 4, 2026, PUCO staff issued a letter recommending that most of the Ohio Companies’ proposed compliance tariffs be approved. The Ohio Companies cannot predict the outcome of the rehearing, but do not expect material changes to the November 2025 order. See “Outlook - State Regulation - Ohio,” in Item 2., "Management's Discussion and Analysis of Financial Condition and Results of Operations". On April 22, 2026, the Ohio Companies filed with the PUCO a notice of their intent to file a three-year rate plan, requesting approval of three consecutive, annual test periods that begin July 1, 2027 and end June 30, 2030. The Ohio Companies filed 47 their applications for an increase in their distribution rates on May 22, 2026. The application proposes net increases in the Ohio Companies’ base distribution revenues of approximately $254 million in the first year, approximately $59 million in the second year, and approximately $80 million in the third year, with a return on equity of 10.2% and a capital structure of approximately 47% debt and approximately 53% equity for all three Ohio Companies. On June 12, 2026, PUCO staff issued a deficiency letter requesting additional supplementation in certain areas, which the Ohio Companies provided on June 22, 2026. On July 1, 2026, an administrative law judge deemed the application complete and set a procedural schedule. Evidentiary hearings are set to begin March 1, 2027. Regulatory Matters - West Virginia On October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC. To ensure that MP and PE can meet their PJM adequacy requirements, the plan proposes, among other things, near-term market capacity purchases and the addition of 70 MWs of solar generation by 2028 and 1,200 MWs of natural gas combined cycle generation by 2031. On February 13, 2026, MP and PE filed a CPCN to construct and operate the proposed generation resources, including a 1,200 MW combined cycle gas turbine plant, that will be known as the Maidsville Energy Center, and 70 MWs of solar generation capacity, for an estimated capital investment of approximately $2.7 billion as of the filing date. The request also includes a surcharge designed to recover financing costs during development and construction of the projects, as well as a transition to recovery in base rates once the projects are placed in service and approved through a base rate case. An evidentiary hearing on the integrated resource plan was held on May 6, 2026, and evidentiary hearings on the CPCN application were held on July 16 and 17, 2026. A final order is expected from the WVPSC in the second half of 2026. On May 15, 2026, MP and PE filed a base rate proceeding proposing an increase in electric rates of $188.4 million, an approximate 10.6% increase in total revenues. The filing includes a base rate increase of $174.6 million and a proposed reliability program and surcharge of $13.8 million. As an alternative, MP and PE requested a phased approach of two increases of $37.9 million effective August 1, 2026, and $37.6 million effective June 1, 2027, with a commitment to abstain from filing another base rate case until April 1, 2028. The WVPSC issued a procedural order on May 21, 2026, on the alternative two-phase approach setting it for hearing on July 9, 2026. On June 11, 2026, the WVPSC staff filed a motion to dismiss, which the WVPSC denied on July 2, 2026. An order is expected from the WVPSC by the end of July 2026. If approved as proposed, new rates associated with the first phase would become effective in August 2026. Regulatory Matters - Maryland PE anticipates filing a base rate distribution case with the MDPSC in the third quarter of 2026, with new rates expected to become effective in the first quarter of 2027. On May 12, 2026, the governor of Maryland signed the Utility RELIEF Act into law. Among other things, the legislation temporarily limits the use of forecasted costs in certain rate proceedings, modifies the standards by which the MDPSC may approve multi-year rate plans, mandates RTO participation, requires additional review of utility spending and cost recovery, eliminates certain utility earnings incentives, imposes restrictions on recovery of certain administrative compensation costs and includes provisions designed to allocate certain transmission and distribution upgrade costs associated with large-load customers, including data centers, to those customers rather than to the broader customer base. FirstEnergy is currently assessing the full extent of the legislation’s impacts, but the Utility RELIEF Act may affect PE’s timing and amount of cost recovery, authorized returns, customer rate structures, infrastructure investment planning, and future earnings opportunities. See “Outlook - State Regulation - Maryland” and “Outlook – FERC Regulatory Matters – RTO Participation ROE Incentive,” in Item 2., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a more fulsome discussion of the current Utility RELIEF Act impacts to PE. Regulatory Matters – New Jersey JCP&L expects to file a base rate case in August 2026. 48 FIRSTENERGY’S CONSOLIDATED RESULTS OF OPERATIONS Second Quarter of 2026 Compared with Second Quarter of 2025 (In millions) For the Three Months Ended June 30, 2026 2025 Increase (Decrease) Revenues $ 3,678 $ 3,380 $ 298 9 % Operating expenses (3,001) (2,734) 267 10 % Other expenses, net (233) (240) (7) (3) % Income taxes (92) (88) 4 5 % Income attributable to noncontrolling interest (64) (50) 14 28 % Earnings attributable to FE $ 288 $ 268 $ 20 7 % Earnings attributable to FE were $288 million or $0.50 per share (basic and diluted) in the second quarter of 2026 compared to $268 million or $0.46 per share (basic and diluted) in the second quarter of 2025, representing an increase of $20 million that was primarily due to the following: •Higher transmission revenues from regulated capital investments that increased rate base and true-up adjustments from the annual forward-looking transmission rate filings; •The absence in 2026 of customer credits associated with the PUCO-approved Ohio Stipulation recognized in 2025; •Higher pension and OPEB non-service credits; •The absence in 2026 of debt redemption costs recognized in 2025; •A reduction in ARO liabilities associated with CCR rules based on the completion of engineering studies and field analysis of certain sites; and •Higher capitalized financing costs. These factors were partially offset by the following: •Higher other operating expenses from planned maintenance expenses; •Lower customer usage and demand; •Higher interest expenses from new long-term debt and convertible note issuances, net of redemptions and repayments; and •Higher investigation and other related costs associated with the ongoing government investigations and ongoing litigation. Detailed segment reporting explanations are included below. Distribution services by customer class are summarized in the following table: For the Three Months Ended June 30, (In thousands) Actual Weather-Adjusted Electric Distribution MWh Deliveries 2026 2025 Increase (Decrease) 2026 2025 Increase (Decrease) Residential 11,734 11,957 (1.9) % 11,750 11,750 — % Commercial(1) 9,468 9,584 (1.2) % 9,476 9,546 (0.7) % Industrial 13,546 12,969 4.4 % 13,546 12,969 4.4 % Total Electric Distribution MWh Deliveries 34,748 34,510 0.7 % 34,772 34,265 1.5 % (1) Includes street lighting. Distribution deliveries in the second quarter of 2026 for the residential and commercial customer classes were lower than the same period of 2025 due to the impact of the milder weather temperatures. Cooling degree days in the second quarter of 2026 were consistent with the same period of 2025 and 6% above normal. Heating degree days in the second quarter of 2026 were 5% below the same period of 2025 and 8% below normal. Industrial deliveries in the second quarter of 2026 compared to the same period of 2025 increased primarily due to growth in the manufacturing sector. 49 FIRSTENERGY’S CONSOLIDATED RESULTS OF OPERATIONS First Six Months of 2026 Compared with First Six Months of 2025 (In millions) For the Six Months Ended June 30, 2026 2025 Increase Revenues $ 7,880 $ 7,145 $ 735 10 % Operating expenses (6,375) (5,745) 630 11 % Other expenses, net (457) (454) 3 1 % Income taxes (230) (214) 16 7 % Income attributable to noncontrolling interest (125) (104) 21 20 % Earnings attributable to FE $ 693 $ 628 $ 65 10 % Earnings attributable to FE were $693 million or $1.20 per share (basic and diluted) in the first six months of 2026 compared to $628 million or $1.09 per share (basic and diluted) in the first six months of 2025, representing an increase of $65 million that was primarily due to the following: •Higher transmission revenues from regulated capital investments that increased rate base and true-up adjustments from the annual forward-looking transmission rate filing; •The absence in 2026 of customer credits associated with the PUCO-approved Ohio Stipulation recognized in 2025; •The absence in 2026 of severance and related costs that were recognized in the first quarter of 2025; •Higher pension and OPEB non-service credits; •Higher capitalized financing costs; •A reduction in ARO liabilities associated with CCR rules based on the completion of engineering studies and field analysis of certain sites; and •The absence in 2026 of debt redemption costs recognized in 2025. These factors were partially offset by the following: •Higher investigation and other related costs associated with the ongoing government investigations and ongoing litigation; •Higher other operating expenses from planned maintenance expenses; and •Higher interest expenses from new long-term debt and convertible note issuances, net of redemptions and repayments. Detailed segment reporting explanations are included below. Distribution services by customer class are summarized in the following table: For the Six Months Ended June 30, (In thousands) Actual Weather-Adjusted Electric Distribution MWh Deliveries 2026 2025 Increase (Decrease) 2026 2025 Increase (Decrease) Residential 27,286 27,448 (0.6) % 27,070 27,134 (0.2) % Commercial(1) 19,573 19,428 0.7 % 19,460 19,403 0.3 % Industrial 26,445 25,806 2.5 % 26,445 25,806 2.5 % Total Electric Distribution MWh Deliveries 73,304 72,682 0.9 % 72,975 72,343 0.9 % (1) Includes street lighting. Distribution deliveries in the first six months of 2026 for the commercial customer class were higher than the same period of 2025, while deliveries to residential customers decreased slightly. Cooling degree days in the first six months of 2026 were 1% above the same period of 2025 and 7% above normal. Heating degree days in the first six months of 2026 were 1% above the same period of 2025 and 1% above normal. Industrial deliveries in the second quarter of 2026 compared to the same period of 2025 increased primarily due to growth in the oil and gas extraction and manufacturing sectors. The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 11., “Segment Information,” of the Combined Notes to Financial Statements of the Registrants. 50 Summary of Results of Operations — Second Quarter 2026 Compared with Second Quarter 2025 Financial results for FirstEnergy’s business segments for the second quarter of 2026 and 2025 were as follows: Second Quarter 2026 Financial Results (In millions) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Revenues: Electric $ 1,679 $ 1,387 $ 537 $ 4 $ 3,607 Other 35 47 7 (18) 71 Total Revenues 1,714 1,434 544 (14) 3,678 Operating Expenses: Fuel — 156 — — 156 Purchased power 608 544 — 5 1,157 Other operating expenses 662 418 95 (10) 1,165 Provision for depreciation 164 142 98 20 424 Amortization (deferral) of regulatory assets, net (163) (63) 1 — (225) General taxes 194 36 84 10 324 Total Operating Expenses 1,465 1,233 278 25 3,001 Other Income (Expense): Miscellaneous income (expense), net 31 24 3 (6) 52 Interest expense (110) (83) (88) (56) (337) Capitalized financing costs 6 19 27 — 52 Total Other Expense (73) (40) (58) (62) (233) Income taxes (benefits) 33 38 47 (26) 92 Income attributable to noncontrolling interest — — 64 — 64 Earnings (Loss) Attributable to FE $ 143 $ 123 $ 97 $ (75) $ 288 Second Quarter 2025 Financial Results (In millions) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Revenues: Electric $ 1,635 $ 1,255 $ 451 $ 4 $ 3,345 Other 40 6 5 (16) 35 Total Revenues 1,675 1,261 456 (12) 3,380 Operating Expenses: Fuel — 168 — — 168 Purchased power 517 432 — 4 953 Other operating expenses 634 306 74 (19) 995 Provision for depreciation 163 139 92 21 415 Amortization (deferral) of regulatory assets, net (98) (3) 2 — (99) General taxes 186 34 75 7 302 Total Operating Expenses 1,402 1,076 243 13 2,734 Other Income (Expense): Debt redemption costs — — — (24) (24) Miscellaneous income (expense), net 25 19 9 (12) 41 Interest expense (101) (68) (81) (49) (299) Capitalized financing costs 7 15 20 — 42 Total Other Expense (69) (34) (52) (85) (240) Income taxes (benefits) 43 35 36 (26) 88 Income attributable to noncontrolling interest — — 50 — 50 Earnings (Loss) Attributable to FE $ 161 $ 116 $ 75 $ (84) $ 268 51 Changes Between Second Quarter 2026 and Second Quarter 2025 Financial Results (In millions) Distribution Integrated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Revenues: Electric $ 44 $ 132 $ 86 $ — $ 262 Other (5) 41 2 (2) 36 Total Revenues 39 173 88 (2) 298 Operating Expenses: Fuel — (12) — — (12) Purchased power 91 112 — 1 204 Other operating expenses 28 112 21 9 170 Provision for depreciation 1 3 6 (1) 9 Amortization (deferral) of regulatory assets, net (65) (60) (1) — (126) General taxes 8 2 9 3 22 Total Operating Expenses 63 157 35 12 267 Other Income (Expense): Debt redemption costs — — — 24 24 Miscellaneous income (expense), net 6 5 (6) 6 11 Interest expense (9) (15) (7) (7) (38) Capitalized financing costs (1) 4 7 — 10 Total Other Expense (4) (6) (6) 23 7 Income taxes (benefits) (10) 3 11 — 4 Income attributable to noncontrolling interest — — 14 — 14 Earnings (Loss) Attributable to FE $ (18) $ 7 $ 22 $ 9 $ 20 52 Distribution Segment — Second Quarter of 2026 Compared with Second Quarter of 2025 Distribution segment’s earnings attributable to FE decreased $18 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to lower customer usage as a result of the milder weather temperatures, higher planned other operating expenses, and higher net financing costs, partially offset by the absence in 2026 of customer credits associated with the PUCO-approved Ohio Stipulation recognized in 2025 and higher pension and OPEB non-service credits. Revenues — Distribution segment’s total revenues increased $39 million as a result of the following sources: For the Three Months Ended June 30, Revenues by Type of Service 2 2026 2025 Increase (Decrease) (In millions) Distribution services $ 1,015 2 $ 1,056 $ (41) Generation sales: Retail 659 576 83 Wholesale 5 3 2 Total generation sales 664 579 85 Other 35 40 (5) Total Revenues $ 1,714 $ 1,675 $ 39 Distribution services revenues decreased $41 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to lower customer usage as a result of the milder weather temperatures and customer restitution and refunds resulting from the Ohio Companies’ PUCO-approved settlement. These restitution and refunds were recognized in the fourth quarter of 2025 and are offset by the amortization of a regulatory liability resulting in no impact to earnings in 2026. The revenue decrease was partially offset by higher rider revenues associated with certain regulated investment programs and the absence in 2026 of customer credits associated with the PUCO-approved Ohio Stipulation recognized in 2025. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings. Generation sales revenues increased $85 million in the second quarter of 2026, as compared to the same period in 2025, primarily due to higher non-shopping generation auction rates. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA was flat in the second quarter of 2026, as compared to the same period of 2025. Retail and wholesale generation sales revenues have no material impact to earnings. Operating Expenses — Total operating expenses increased $63 million, primarily due to: •Purchased power costs, which have no material impact to earnings, increased $91 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to higher unit costs as described above. •Other operating expenses increased $28 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to: •Higher network transmission expenses of $9 million, which are deferred for future recovery, resulting in no material impact to earnings; •Higher energy efficiency and other state mandated program costs of $2 million, which were deferred for future recovery, resulting in no material impact to earnings; •Higher storm restoration expenses of $5 million, which were deferred for future recovery; and •Higher other operating expenses of $28 million, primarily due to planned maintenance expenses. The increase was partially offset by: •Lower planned vegetation management expenses of $6 million, primarily due to accelerated work in 2025 in Pennsylvania; and •A $10 million reduction in ARO liabilities associated with CCR rules based on the completion of engineering studies and field analysis of certain sites. 53 •Depreciation expense increased $1 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to a higher asset base, partially offset by a change in depreciation rates effective March 1, 2026, as a result of the Ohio Base Rate Case. •Deferral of regulatory assets increased $65 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher deferred storm restoration expenses of $5 million, a $99 million increase in the amortization of a regulatory liability as a result of providing restitution and refunds to Ohio customers, as further discussed below, partially offset by a $7 million net decrease in generation and transmission deferrals, a $7 million decrease from lower deferral of costs associated with customer assistance programs, an $11 million increase in amortization associated with recovery of previously incurred storm costs and a $14 million net decrease in other deferrals. •General taxes increased $8 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher property and gross receipts taxes. Other Expense — Other expense increased $4 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issuances since the second quarter of 2025 and lower capitalized interest, partially offset by higher pension and OPEB non-service credits. Income Taxes — Distribution segment’s effective tax rate was 18.8% and 21.1% for the three months ended June 30, 2026, and 2025, respectively. The decrease in the effective tax rate was primarily due to increases in tax benefits associated with state flow-through and a remeasurement of the reserve for an uncertain tax position in the second quarter of 2026. Integrated Segment — Second Quarter of 2026 Compared with Second Quarter of 2025 Integrated segment’s earnings attributable to FE increased $7 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher transmission revenues from regulated capital investments that increased rate base, true-up adjustments from the annual forward-looking transmission rate filing and increased customer usage and demand. Revenues — Integrated segment’s total revenues increased $173 million as a result of the following sources: For the Three Months Ended June 30, Revenues by Type of Service 2 2026 2025 Increase (Decrease) (In millions) Distribution services $ 376 $ 384 $ (8) Generation sales: Retail 737 682 55 Wholesale 125 78 47 Total generation sales $ 862 $ 760 $ 102 Transmission revenues: JCP&L 89 63 26 MP & PE 60 48 12 Total transmission revenues $ 149 $ 111 $ 38 Other 47 6 41 Total Revenues $ 1,434 $ 1,261 $ 173 Distribution services revenues decreased $8 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to lower rider revenues and return of certain ZEC refunds in New Jersey as further described below. These refunds were offset by the amortization of a regulatory liability resulting in no impact to earnings. The decrease in distribution services revenues was partially offset by higher customer demands and higher recovery of transmission expenses, the recovery of which has no material impact to earnings. 54 Generation sales revenues increased $102 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to: •Retail generation sales increased $55 million in the second quarter of 2026, as compared to the same period in 2025, primarily due to higher non-shopping generation auction rates and higher volumes as a result of the weather temperatures. Retail generation sales, other than those in West Virginia, have no material impact to earnings. •Wholesale generation revenues increased $47 million in the second quarter of 2026, as compared to the same period in 2025, primarily due to higher wholesale rates and capacity revenues, partially offset by lower sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings. Transmission revenues increased $38 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher recovery of transmission operating expenses, true-up adjustments from the annual forward-looking transmission rate filing and higher rate base from regulated investment programs. Other revenues increased $41 million in the second quarter of 2026, as compared to the same period of 2025, due to higher FTR credits, which offset higher transmission congestion charges. Due to the ENEC, FTRs have no material impact to earnings. Operating Expenses — Total operating expenses increased $157 million, primarily due to: •Fuel costs decreased $12 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to lower consumption volumes, partially offset by higher unit costs. Due to the ENEC, fuel expense has no material impact to earnings. •Purchased power costs, which have no material impact to earnings, increased $112 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to higher volumes, capacity expenses and prices. •Other operating expenses increased $112 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to: •Higher network transmission expenses of $15 million, which were deferred for future recovery, resulting in no material impact to earnings; •Higher transmission congestion charges of $21 million. Due to the ENEC, congestion charges, net of FTR revenue, have no material impact to earnings; •Higher storm restoration expenses of $40 million, which were mostly deferred for future recovery; •Higher formula rate transmission operating and maintenance expenses of $13 million, which have no material impact to earnings; and •Higher energy efficiency and other state mandated program costs of $23 million, which were deferred for future recovery, resulting in no material impact to earnings. •Depreciation expense increased $3 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to a higher asset base. •Deferral of regulatory assets increased $60 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to $42 million in higher deferral of storm related expenses, a $9 million net increase from higher generation and transmission related deferrals, a $5 million increase related to the amortization of a regulatory liability associated with ZEC refunds, further described below, and $4 million related to net increases in other deferrals. Other Expense — Other expense increased $6 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issuances since the second quarter 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits. Income Taxes — Integrated segment’s effective tax rate was 23.6% and 23.2% for the three months ended June 30, 2026, and 2025, respectively. 55 Stand-Alone Transmission Segment — Second Quarter of 2026 Compared with Second Quarter of 2025 Stand-Alone Transmission segment’s earnings attributable to FE increased $22 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher revenues from regulated capital investments that increased rate base, true-up adjustments from the annual forward-looking transmission rate filings, and higher capitalized financing costs, partially offset by higher interest expenses from new long-term debt issuances. Revenues — Stand-Alone Transmission segment’s total revenues increased $88 million, primarily due to a higher overall rate base, higher recovery of transmission operating expenses, and true-up adjustments from the annual forward-looking transmission rate filings. The following table shows revenues by transmission asset owner: For the Three Months Ended June 30, Revenues by Transmission Asset Owner 1 2026 2025 Increase (In millions) ATSI $ 299 $ 259 $ 40 TrAIL 64 62 2 MAIT 150 114 36 KATCo 31 21 10 Total Revenues $ 544 $ 456 $ 88 Operating Expenses — Total operating expenses increased $35 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher depreciation and property tax expenses from a higher asset base and planned operating and maintenance expenses. Nearly all operating expenses are recovered through formula rates. Other Expense — Total other expense increased $6 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher interest expenses from new long-term debt issuances and higher interest on transmission revenue collection balances, partially offset by higher capitalized financing costs. Income Taxes — Stand-Alone Transmission segment’s effective tax rate was 22.6% and 22.4% for the three months ended June 30, 2026, and 2025, respectively. Corporate / Other — Second Quarter 2026 Compared with Second Quarter 2025 Financial results at Corporate/Other resulted in a $9 million decrease in losses attributable to FE in the second quarter of 2026, as compared to the same period of 2025, primarily due to the absence in 2026 of debt redemption costs recognized in 2025, partially offset by higher investigation and other related costs associated with the ongoing government investigations and ongoing litigation, and higher interest expense associated with the convertible notes issuances, net of redemptions and repayments. 56 Summary of Results of Operations — First Six Months of 2026 Compared with First Six Months of 2025 Financial results for FirstEnergy’s business segments for the first six months of 2026 and 2025 were as follows: First Six Months 2026 Financial Results (In millions) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Revenues: Electric $ 3,629 $ 2,929 $ 1,046 $ 14 $ 7,618 Other 75 208 14 (35) 262 Total Revenues 3,704 3,137 1,060 (21) 7,880 Operating Expenses: Fuel — 317 — — 317 Purchased power 1,370 1,207 — 9 2,586 Other operating expenses 1,378 1,090 174 (17) 2,625 Provision for depreciation 329 281 195 40 845 Amortization (deferral) of regulatory assets, net (417) (268) 3 — (682) General taxes 417 76 167 24 684 Total Operating Expenses 3,077 2,703 539 56 6,375 Other Income (Expense): Miscellaneous income (expense), net 60 50 6 (16) 100 Interest expense (217) (161) (173) (112) (663) Capitalized financing costs 16 37 52 1 106 Total Other Expense (141) (74) (115) (127) (457) Income taxes (benefits) 97 84 93 (44) 230 Income attributable to noncontrolling interest — — 125 — 125 Earnings (Loss) Attributable to FE $ 389 $ 276 $ 188 $ (160) $ 693 First Six Months 2025 Financial Results (In millions) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Revenues: Electric $ 3,531 $ 2,588 $ 937 $ 8 $ 7,064 Other 80 22 10 (31) 81 Total Revenues 3,611 2,610 947 (23) 7,145 Operating Expenses: Fuel — 317 — — 317 Purchased power 1,127 904 — 10 2,041 Other operating expenses 1,261 643 172 (47) 2,029 Provision for depreciation 325 277 183 41 826 Amortization (deferral) of regulatory assets, net (117) 5 3 — (109) General taxes 396 71 149 25 641 Total Operating Expenses 2,992 2,217 507 29 5,745 Other Income (Expense): Debt redemption costs — — — (24) (24) Miscellaneous income (expense), net 51 37 13 (24) 77 Interest expense (200) (133) (154) (100) (587) Capitalized financing costs 12 30 37 1 80 Total Other Expense (137) (66) (104) (147) (454) Income taxes (benefits) 103 75 76 (40) 214 Income attributable to noncontrolling interest — — 104 — 104 Earnings (Loss) Attributable to FE $ 379 $ 252 $ 156 $ (159) $ 628 57 Changes Between First Six Months 2026 and First Six Months 2025 Financial Results (In millions) Distribution Integrated Stand-Alone Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Revenues: Electric $ 98 $ 341 $ 109 $ 6 $ 554 Other (5) 186 4 (4) 181 Total Revenues 93 527 113 2 735 Operating Expenses: Fuel — — — — — Purchased power 243 303 — (1) 545 Other operating expenses 117 447 2 30 596 Provision for depreciation 4 4 12 (1) 19 Amortization (deferral) of regulatory assets, net (300) (273) — — (573) General taxes 21 5 18 (1) 43 Total Operating Expenses 85 486 32 27 630 Other Income (Expense): Debt redemption costs — — — 24 24 Miscellaneous income (expense), net 9 13 (7) 8 23 Interest expense (17) (28) (19) (12) (76) Capitalized financing costs 4 7 15 — 26 Total Other Expense (4) (8) (11) 20 (3) Income taxes (benefits) (6) 9 17 (4) 16 Income attributable to noncontrolling interest — — 21 — 21 Earnings (Loss) Attributable to FE $ 10 $ 24 $ 32 $ (1) $ 65 58 Distribution Segment — First Six Months of 2026 Compared with First Six Months of 2025 Distribution segment’s earnings attributable to FE increased $10 million in the first six months of 2026, as compared to the same period of 2025, primarily due to the absence in 2026 of severance and related costs that were recognized in the first quarter of 2025, the absence in 2026 of customer credits associated with the PUCO-approved Ohio Stipulation recognized in 2025 and a reduction in ARO liabilities, partially offset by lower customer usage and demand and higher planned operating expenses. Revenues — Distribution segment’s total revenues increased $93 million as a result of the following sources: For the Six Months Ended June 30, Revenues by Type of Service 2026 2025 Increase (Decrease) (In millions) Distribution services $ 2,104 $ 2,235 $ (131) Generation sales: Retail 1,516 1,292 224 Wholesale 9 4 5 Total generation sales 1,525 1,296 229 Other 75 80 (5) Total Revenues $ 3,704 $ 3,611 $ 93 Distribution services revenues decreased $131 million in the first six months of 2026, as compared to the same period of 2025, primarily due to lower customer usage as a result of the milder weather temperatures and customer restitution and refunds resulting from the Ohio Companies’ PUCO-approved settlement. These restitution and refunds were recognized in the fourth quarter of 2025 and are offset by the amortization of a regulatory liability resulting in no impact to earnings in 2026. The revenue decrease was partially offset by higher rider revenues associated with certain regulated investment programs and the absence in 2026 of customer credits associated with the PUCO-approved Ohio Stipulation recognized in 2025. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings. Generation sales revenues increased $229 million in the first six months of 2026, as compared to the same period in 2025, primarily due to higher non-shopping generation auction rates and higher retail generation sales volumes as a result of lower shopping, which increased sales volumes. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies decreased to 88% from 89% in Ohio and was flat in Pennsylvania in the first six months of 2026, as compared to the same period of 2025. Retail and wholesale generation sales revenue have no material impact to earnings. Operating Expenses — Total operating expenses increased $85 million, primarily due to: •Purchased power costs, which have no material impact to earnings, increased $243 million during the first six months of 2026, as compared to the same period of 2025, primarily due to higher unit costs and generation sales volumes as described above. •Other operating expenses increased $117 million in the first six months of 2026, as compared to the same period of 2025, primarily due to: •Higher network transmission expenses of $37 million, which were deferred for future recovery, resulting in no material impact to earnings; •Higher energy efficiency and other state mandated program costs of $23 million, which were deferred for future recovery, resulting in no material impact to earnings; •Higher other operating expenses of $19 million, primarily due to planned maintenance expenses; and •Higher storm restoration expenses of $80 million, which were deferred for future recovery. The increase was partially offset by: •Lower planned vegetation management expenses of $14 million, primarily due to accelerated work in 2025 in Pennsylvania; •Lower uncollectible expenses of $4 million; which were deferred for future recovery, resulting in no material impact to earnings; 59 •A $10 million reduction in ARO liabilities associated with CCR rules based on the completion of engineering studies and field analysis of certain sites; and •The absence in 2026 of $14 million of severance and related costs associated with FirstEnergy’s organizational changes announced and recognized in the first quarter of 2025. •Depreciation expense increased $4 million in the first six months of 2026, as compared to the same period of 2025, primarily due to a higher asset base, partially offset by a change in depreciation rates effective March 1, 2026, as a result of the Ohio Base Rate Case. •Deferral of regulatory assets increased $300 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher deferred storm restoration expenses of $80 million, a $250 million increase in the amortization of a regulatory liability as a result of providing restitution and refunds to Ohio customers and a $22 million net increase in generation and transmission deferrals, partially offset by a $16 million increase in amortization associated with recovery of previously incurred storm costs, an $18 million decrease from lower deferral of costs associated with customer assistance programs and a $18 million net decrease in other deferrals. •General taxes increased $21 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher property and gross receipts taxes. Other Expense — Other expense increased $4 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issuances since the first quarter of 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits. Income Taxes — Distribution segment’s effective tax rate was 20.0% and 21.4% for the six months ended June 30, 2026, and 2025, respectively. The decrease in the effective tax rate was primarily due to increases in tax benefits associated with state flow-through and a remeasurement of the reserve for an uncertain tax position in the second quarter of 2026. Integrated Segment — First Six Months of 2026 Compared with First Six Months of 2025 Integrated segment’s earnings attributable to FE increased $24 million in the first six months of 2026, as compared to the same period of 2025, primarily due to the absence in 2026 of severance and related costs that were recognized in the first quarter of 2025, higher transmission revenues from regulated capital investments that increased rate base, true-up adjustments from the annual forward-looking transmission rate filing, increased customer usage and demand, and higher pension and OPEB non-service credits, partially offset by higher other operating expenses and higher net financing costs. Revenues — Integrated segment’s total revenues increased $527 million as a result of the following sources: For the Six Months Ended June 30, Revenues by Type of Service 2026 2025 Increase (In millions) Distribution services (1) $ 818 $ 815 $ 3 Generation sales: Retail 1,606 1,437 169 Wholesale 237 125 112 Total generation sales 1,843 1,562 281 Transmission revenues: JCP&L 160 124 36 MP & PE 108 87 21 Total transmission revenues 268 211 57 Other 208 22 186 Total Revenues $ 3,137 $ 2,610 $ 527 (1) Includes $13 million of ARP revenues in 2026, related to lost distribution revenues associated with energy efficiency in New Jersey. 60 Distribution services revenues increased $3 million in the first six months of 2026, as compared to the same period of 2025, primarily resulting from higher customer usage as a result of the weather temperatures and higher rider revenues associated with certain regulated investment programs, partially offset by the return of certain ZEC refunds in New Jersey as further described below. These refunds were offset by the amortization of a regulatory liability resulting in no impact to earnings. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings. Generation sales revenues increased $281 million in the first six months of 2026, as compared to the same period of 2025. •Retail generation sales increased $169 million in the first six months of 2026, as compared to the same period in 2025, primarily due to higher non-shopping generation auction rates and higher volumes as a result of the weather temperatures. Retail generation sales, other than those in West Virginia, have no material impact to earnings. •Wholesale generation revenues increased $112 million in the first six months of 2026, as compared to the same period in 2025, primarily due to higher wholesale rates and capacity revenues, partially offset by lower sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings. Transmission revenues increased $57 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher recovery of transmission operating expenses, true-up adjustments from the annual forward-looking transmission rate filing and higher rate base from regulated investment programs. Other revenues increased $186 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher FTR credits in the first quarter of 2026, which offset higher transmission congestion charges. Due to the ENEC, FTRs have no material impact to earnings. Operating Expenses — Total operating expenses increased $486 million, primarily due to: •Fuel costs were flat during the first six months of 2026, as compared to the same period of 2025, primarily due to higher unit costs, offset by lower consumption volumes. Due to the ENEC, fuel expense has no material impact to earnings. •Purchased power costs, which have no material impact to earnings, increased $303 million during the first six months of 2026, as compared to the same period of 2025, primarily due to higher volumes, capacity expenses and prices, which were impacted by the Winter Storm Fern weather event in the first quarter of 2026. •Other operating expenses increased $447 million in the first six months of 2026, as compared to the same period of 2025, primarily due to: •Higher network transmission expenses of $40 million, which were deferred for future recovery, resulting in no material impact to earnings; •Higher transmission congestion charges of $242 million, primarily in the first quarter of 2026 from the net impacts of the Winter Storm Fern weather event. Due to the ENEC, congestion charges, net of FTR revenue, have no material impact to earnings; •Higher storm restoration expenses of $117 million, of which $113 million were deferred for future recovery; •Higher formula rate transmission operating and maintenance expenses of $16 million, which have no material impact to earnings; •Higher vegetation management expenses of $8 million, which were mostly deferred for future recovery, resulting in no material impact to earnings; and •Higher energy efficiency and other state mandated program costs of $38 million, which were deferred for future recovery, resulting in no material impact to earnings. The increase was partially offset by: •The absence in 2026 of $11 million of severance and related costs associated with FirstEnergy’s organizational changes announced and recognized in the first quarter of 2025; and •Lower other operating expenses of $3 million, primarily due to the absence in 2026 of a legal reserve recognized in the second quarter of 2025, partially offset by higher regulated generation outage spend and planned maintenance expenses. •Deferral of regulatory assets increased $273 million in the first six months of 2026, as compared to the same period of 2025, primarily due to $113 million in higher deferral of storm related expenses, a $5 million increase related to the amortization of a regulatory liability associated with ZEC refunds, further described below, and a $155 million net increase from higher generation and transmission related deferrals. 61 •General taxes increased $5 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher property taxes. Other Expense — Other expense increased $8 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issuances since the first quarter of 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits. Income Taxes — Integrated segment’s effective tax rate was 23.3% and 22.9% for the six months ended June 30, 2026, and 2025, respectively. Stand-Alone Transmission Segment — First Six Months of 2026 Compared with First Six Months of 2025 Stand-Alone Transmission segment’s earnings attributable to FE increased $32 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher revenues from regulated capital investments that increased rate base, true-up adjustments from the annual forward-looking transmission rate filings, and higher capitalized financing costs, partially offset by higher interest expenses from new long-term debt issuances. Revenues — Stand-Alone Transmission segment’s total revenues increased $113 million, primarily due to a higher overall rate base, higher recovery of transmission operating expenses, and true-up adjustments from the annual forward-looking transmission rate filings. The following table shows revenues by transmission asset owner: For the Six Months Ended June 30, Revenues by Transmission Asset Owner 2026 2025 Increase (Decrease) (In millions) ATSI $ 585 $ 524 $ 61 TrAIL 131 133 (2) MAIT 289 246 43 KATCo 55 44 11 Total Revenues $ 1,060 $ 947 $ 113 Operating Expenses — Total operating expenses increased $32 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher depreciation and property tax expenses from a higher asset base and planned operating and maintenance expenses. Nearly all operating expenses are recovered through formula rates. Other Expense — Total other expense increased $11 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher interest expenses from new long-term debt issuances and higher interest on transmission revenue collection balances, partially offset by higher capitalized financing costs. Income Taxes — Stand-Alone Transmission segment’s effective tax rate was 22.9% and 22.6% for the six months ended June 30, 2026, and 2025, respectively. 62 Corporate / Other — First Six Months of 2026 Compared with First Six Months of 2025 Financial results at Corporate/Other resulted in a $1 million increase in losses attributable to FE in the first six months of 2026, as compared to the same period of 2025, primarily due to: •$17 million (after-tax) of higher investigation and other related costs associated with the ongoing government investigations and ongoing litigation; and •$8 million (after-tax) of higher interest expense associated with the convertible notes issuances, net of redemptions and repayments. The increase in losses was partially offset by: •$18 million (after-tax) due to the absence in 2026 of debt redemption costs recognized in 2025; •$3 million (after-tax) of higher income associated with a legacy purchase power contract; and •Higher discrete tax benefits in 2026 compared to 2025. REGULATORY ASSETS AND LIABILITIES Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. The Registrants net their regulatory assets and liabilities based on federal and state jurisdictions. Management assesses the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability relate to changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets and liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. FirstEnergy has regulatory assets of approximately $1.4 billion and $829 million, and regulatory liabilities of $891 million and approximately $1.2 billion as of June 30, 2026, and December 31, 2025, respectively. The following table provides information about the composition of FirstEnergy’s net regulatory assets and liabilities as of June 30, 2026, and December 31, 2025, and the changes during the six months ended June 30, 2026: Net Regulatory Assets (Liabilities) by Source - FirstEnergy June 30, 2026 December 31, 2025 Change (In millions) Customer payables for future income taxes $ (1,977) $ (2,041) $ 64 Spent nuclear fuel disposal costs (74) (76) 2 Asset removal costs (586) (675) 89 Deferred transmission costs (44) (43) (1) Deferred generation costs 543 405 138 Deferred distribution costs 520 466 54 Storm-related costs 1,360 1,122 238 Energy efficiency program costs 545 462 83 New Jersey societal benefit costs 62 80 (18) Vegetation management costs 162 153 9 Ohio settlement charges (1) (250) 249 New Jersey ZEC refunds (80) (4) (76) Other 36 45 (9) Net Regulatory Assets (Liabilities) included on FirstEnergy’s Consolidated Balance Sheets $ 466 $ (356) $ 822 63 The following table provides information about the composition of JCP&L’s net regulatory assets and liabilities as of June 30, 2026, and December 31, 2025, and the changes during the six months ended June 30, 2026: Net Regulatory Assets (Liabilities) by Source - JCP&L June 30, 2026 December 31, 2025 Change (In millions) Customer payables for future income taxes $ (384) $ (393) $ 9 Spent nuclear fuel disposal costs (74) (76) 2 Asset removal costs (64) (87) 23 Deferred transmission costs (22) (25) 3 Deferred generation costs 31 (10) 41 Deferred distribution costs 327 318 9 Storm-related costs 477 367 110 Energy efficiency program costs 419 316 103 New Jersey societal benefit costs 62 80 (18) New Jersey ZEC refunds (80) (4) (76) Other 30 29 1 Net Regulatory Assets included on JCP&L’s Balance Sheets $ 722 $ 515 $ 207 The following is a description of the regulatory assets and liabilities described above: Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to federal and state tax rate changes such as the TCJA and Pennsylvania House Bill 1342. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset. Spent nuclear fuel disposal costs - Reflects amounts collected from customers, and the investment income, losses and changes in fair value of the trusts for spent nuclear fuel disposal costs related to former nuclear generation facilities, Oyster Creek and Three Mile Island Unit 1. Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement. Deferred transmission costs - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement. Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034), the Warrior Run purchased power agreement termination fee at PE (amortized through 2029), and the ENEC at MP and PE. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC, which reflects the impact of Winter Storm Fern in 2026. Generally, the ENEC rate is updated annually. Deferred distribution costs - Primarily relates to the Ohio Companies' deferral of certain distribution-related expenses, including interest (amortized through 2034) and JCP&L’s AMI program costs. Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $667 million and $87 million for FirstEnergy and JCP&L, respectively, are currently being recovered through rates as of June 30, 2026. Approximately $335 million and $73 million for FirstEnergy and JCP&L, respectively, were being recovered through rates as of December 31, 2025. Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including New Jersey energy efficiency and renewable energy programs, FE PA's Energy Efficiency and Conservation programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland Surcharge. Investments in certain of these energy efficiency programs earn a long-term return. 64 New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and the New Jersey Clean Energy Program. Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey, certain distribution and transmission vegetation management costs in West Virginia, and certain transmission vegetation management costs at ATSI (amortized through 2030) and KATCo (amortized through 2036). Ohio settlement charges - Reflects restitution and refunds owed to customers associated with the Ohio Companies' PUCO-approved settlement order, which began to be provided to customers in February 2026, and has been substantially refunded to customers as of June 30, 2026. See Note 9., "Regulatory Matters," of the Combined Notes to Financial Statements of the Registrants for additional details. New Jersey ZEC refunds - Reflects refunds owed to customers associated with the NJBPU's order requiring certain nuclear generating units to return duplicate ZEC payments received during 2024. See Note 9., "Regulatory Matters," of the Combined Notes to Financial Statements of the Registrants for additional details. The following table provides information about the composition of FirstEnergy’s net regulatory assets that do not earn a current return as of June 30, 2026, and December 31, 2025, of which approximately $916 million and $802 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction: Regulatory Assets by Source Not Earning a Current Return - FirstEnergy June 30,2026 December 31,2025 Change (In millions) Deferred generation costs $ 398 $ 280 $ 118 Deferred distribution costs 183 199 (16) Storm-related costs 1,015 844 171 Other 85 102 (17) FirstEnergy Regulatory Assets Not Earning a Current Return $ 1,681 $ 1,425 $ 256 The following table provides information about the composition of JCP&L’s net regulatory assets that do not earn a current return as of June 30, 2026, and December 31, 2025, of which approximately $91 million and $76 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral: Regulatory Assets by Source Not Earning a Current Return - JCP&L June 30,2026 December 31,2025 Change (In millions) Deferred distribution costs $ 130 $ 147 $ (17) Storm-related costs 477 367 110 Other 24 24 — JCP&L Regulatory Assets Not Earning a Current Return $ 631 $ 538 $ 93 CAPITAL RESOURCES AND LIQUIDITY The Registrants’ businesses are capital intensive, requiring significant resources to fund operating expenses, construction and other investment expenditures, scheduled debt maturities and interest payments, dividend payments and potential contributions to the pension plan. The Registrants expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for the remainder of 2026 and beyond, the Registrants expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by the Registrants, which may include hybrid securities by FE to, among other things, fund capital expenditures and other capital-like investments, and refinance short-term and maturing long-term debt, subject to market conditions and other factors. Additionally, FE may issue its common equity to fund capital expenditures in its 2026 through 2030 planning period averaging approximately 1% of its current market capitalization in each year of the planning period, subject to market conditions and other factors. 65 In alignment with FirstEnergy’s strategy to invest in its segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated subsidiaries to issue and/or refinance debt. Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time. FirstEnergy continues to monitor supply lead times in light of demand increases across the industry, including due to data center usage, and the imposition of tariffs and retaliatory tariffs that have been, and may be, imposed by the U.S. government in response. In addition, ongoing geopolitical conflicts have contributed to volatility in global energy markets and fuel and transportation costs, which may further impact supply availability or pricing. FirstEnergy continues to implement mitigation strategies to address volatility in interest rates, inflation and supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, a prolonged continuation or further increase in demand, sustained or escalating geopolitical tensions, rising fuel costs or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition. As of June 30, 2026, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was approximately $2.7 billion, primarily due to current portion of long-term debt, accounts payable, short-term borrowings and accrued interest, taxes, and compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below. As of June 30, 2026, JCP&L’s net deficit in working capital (current assets less current liabilities) was approximately $207 million, primarily due to accounts payable, short-term borrowings, accrued interest, and compensation and benefits. JCP&L believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below. Short-Term Borrowings / Revolving Credit Facilities On October 27, 2025, FE, the Electric Companies, Transmission Companies, and FET, each entered into an amended credit facility to, among other things: (i) remove the 10 basis point credit spread adjustment from the interest rate calculation; (ii) permit a one-week interest period for any Term Benchmark Advance (as defined under each of the Amended Credit Facilities) based upon daily simple SOFR; and (iii) extend the maturity date of each credit facility for an additional one-year period (a) from October 20, 2028 to October 20, 2029 for the KATCo credit facility, (b) from October 20, 2029 to October 20, 2030 for the FET credit facility and (c) from October 18, 2028 to October 18, 2029 for the remaining Amended Credit Facilities. Borrowings under each of the Amended Credit Facilities may be used for working capital and other general corporate purposes. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Amended Credit Facilities contains financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Amended Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its credit facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters. Each of the Amended Credit Facilities bears interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on FirstEnergy’s results of operations, cash flows, financial condition and liquidity. FE Term Loan Facility On April 28, 2026, FE entered into the $750 million FE Term Loan Facility with a maturity date of April 27, 2027, which was fully drawn upon execution. The FE Term Loan Facility contains covenants and other terms and conditions substantially similar to those applicable to FE under the Amended Credit Facilities, including the same requirement to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters. Proceeds were used to repay short-term borrowings outstanding under the Amended Credit Facilities. 66 FirstEnergy had $1,376 million and $325 million of outstanding short-term borrowings as of June 30, 2026, and December 31, 2025, respectively. FirstEnergy’s available liquidity as of July 27, 2026, was as follows: Revolving Credit Facilities Maturity Commitment Available Liquidity (In millions) FE October 2029 $ 1,000 $ 897 FET October 2030 1,000 695 Ohio Companies October 2029 800 453 FE PA October 2029 950 949 JCP&L October 2029 750 450 MP and PE October 2029 400 369 ATSI, MAIT and TrAIL October 2029 850 849 KATCo October 2029 150 150 Subtotal $ 5,900 $ 4,812 Cash and cash equivalents — 72 Total $ 5,900 $ 4,884 The following table summarizes the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of June 30, 2026: Individual Borrower Regulatory Debt Limitations Credit Facility Commitment Actual Debt-to-Total-Capitalization Ratio (In millions) FE N/A $ 1,000 N/A(2) ATSI(1) $ 500 350 40.6 % CEI(1) 750 300 47.2 % FET N/A 1,000 65.9 % FE PA(1) 1,250 950 48.2 % JCP&L(1) 1,500 750 41.7 % KATCo(1) 200 150 28.2 % MAIT(1) 400 350 38.8 % MP(1) 900 250 48.5 % OE(1) 500 300 51.0 % PE(1) 450 150 49.8 % TE(1) 300 200 54.5 % TrAIL(1) 400 150 39.6 % (1) Regulatory debt limitations include amounts which may be borrowed under the regulated companies’ money pool. (2) FE is not required to maintain a debt-to-total-capitalization ratio under its credit facility. However, FE is required to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters. FE's consolidated interest coverage ratio as of June 30, 2026, was approximately 4.2 times. 67 Subject to each borrower’s sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the Amended Credit Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Amended Credit Facilities and against the applicable borrower’s borrowing sublimit. As of June 30, 2026, FirstEnergy had $210 million in outstanding LOCs, $63 million of which are issued under the Amended Credit Facilities. Revolving Credit Facility LOC Availability as of June 30, 2026 LOC Utilized as of June 30, 2026 (In millions) FE $ 100 $ 3 FET 100 — Ohio Companies 150 27 FE PA 200 1 JCP&L 100 — MP and PE 100 31 ATSI, MAIT and TrAIL 200 1 KATCo 35 — Each of the Amended Credit Facilities does not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Amended Credit Facilities is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the credit facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million. As of June 30, 2026, FE was in compliance with its applicable consolidated interest coverage ratio and the Electric Companies, the Transmission Companies, and FET were each in compliance with their debt-to-total-capitalization ratio covenants under each of their Amended Credit Facilities. FirstEnergy Money Pools FirstEnergy’s regulated operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. Average Interest Rates Regulated Companies’ Money Pool Unregulated Companies’ Money Pool 2026 2025 2026 2025 For the Three Months Ended June 30, 4.35 % 4.72 % 4.09 % 5.71 % For the Six Months Ended June 30, 4.29 % 4.83 % 4.03 % 5.58 % 68 Long-Term Debt Capacity FE’s and its subsidiaries’ access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of July 27, 2026: Corporate Credit Rating Senior Secured Senior Unsecured Outlook/Credit Watch(1) Issuer S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch FE BBB+ Baa3 BBB — — — BBB Baa3 BBB S P S Distribution: CEI BBB+ Baa3 BBB+ — — — BBB+ Baa3 A- S S P OE A- A3 BBB+ A A1 A A- A3 A- S S P TE BBB+ Baa2 BBB+ A A3 A — — — S S P FE PA A- A3 A- A A1 — A- A3 A S S S Integrated: JCP&L BBB+ A3 A- — — — BBB+ A3 A S S S MP BBB Baa2 A- A- A3 A+ — Baa2 — P S S AGC BBB- Baa2 A- — — — — — — S S S PE BBB Baa2 BBB+ A- A3 A — — — P S S Stand-Alone Transmission: FET A Baa2 BBB+ — — — A- Baa2 BBB+ S S S ATSI A A3 A — — — A A3 A+ S S S MAIT A A3 A — — — A A3 A+ S S S TrAIL A A3 A — — — A A3 A+ S S S KATCo — A3 A- — — — — — — — S S (1) S = Stable, P = Positive On March 30, 2026, Moody’s revised FE’s outlook to positive from stable. Moody’s also affirmed FE’s ratings, including its Baa3 Issuer and senior unsecured ratings. The applicable undrawn and drawn margin on the credit facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments and on actual borrowings under the credit facilities are based on FE’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s. The interest rates payable on approximately $2.1 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable governing documents. Generally, a one-notch downgrade by the applicable rating agency may result in a 25 basis point coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate. Debt capacity is subject to the consolidated interest coverage ratio in FE's credit facility. As of June 30, 2026, FirstEnergy could incur approximately $0.9 billion of incremental interest expense or incur a $2.2 billion reduction to the consolidated interest coverage earnings numerator, as defined under the covenant, and FE would remain within the limitations of the financial covenant requirements of FE's credit facility. As of June 30, 2026, JCP&L could incur approximately $6.1 billion of additional debt or incur an approximate $3.3 billion reduction to equity, as defined under the debt to capital covenant, and JCP&L would remain within the limitations of the financial covenant requirements of JCP&L's credit facility. Cash Requirements and Commitments The Registrants have certain obligations and commitments to make future payments under contracts. For an in-depth discussion of the Registrants’ cash requirements and commitments, see “Capital Resources and Liquidity - Cash Requirements and Commitments" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" within the Registrants’ Form 10-K for the year ended December 31, 2025 (filed on February 18, 2026). 69 Changes in Cash Position As of June 30, 2026, FirstEnergy had $63 million of cash and cash equivalents and $128 million of restricted cash as compared to $57 million of cash and cash equivalents and $42 million of restricted cash as of December 31, 2025, on the Consolidated Balance Sheets. The following table summarizes the major classes of cash flow items: For the Six Months Ended June 30, (In millions) 2026 2025 Change Net cash provided from operating activities $ 1,137 $ 1,719 $ (582) Net cash used for investing activities (2,828) (2,414) (414) Net cash provided from financing activities 1,783 1,155 628 Net change in cash, cash equivalents, and restricted cash 92 460 (368) Cash, cash equivalents, and restricted cash at beginning of period 99 154 (55) Cash, cash equivalents, and restricted cash at end of period $ 191 $ 614 $ (423) Cash Flows From Operating Activities FirstEnergy’s most significant sources of cash are derived from electric service provided by its operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve shopping customers, and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services. Net cash provided from operating activities was $1.1 billion in the first six months of 2026, as compared to net cash provided from operating activities of $1.7 billion in the first six months of 2025. The decrease in cash provided from operating activities in 2026, compared to the same period of 2025, is primarily due to: •Restitution and refunds returned to Ohio customers resulting from the PUCO-approved settlement, which began to be provided to customers in February 2026; •Higher storm restoration costs; •Higher transmission and purchased power costs, primarily from the net impacts of the Winter Storm Fern weather event in the first quarter of 2026; •Lower net transmission revenue collections based on the timing of formula rate collections; and •Decreased working capital due to the timing of accounts payable and higher employee benefit payments in the first quarter of 2026, as compared to the same period in 2025. The decrease in cash provided from operating activities was partially offset by: •Receipt of New Jersey ZEC refunds, which will be returned to customers over the next 12 months; •Higher return on regulated capital investment programs; and •Temporary rate credits that were provided to JCP&L residential customers during the third quarter of 2025 that were recovered in the first quarter of 2026. 70 Cash Flows From Investing Activities Net cash used for investing activities in the first six months of 2026 principally represented cash used for capital investments. The following table summarizes investing activities for the first six months of 2026 and 2025: For the Six Months Ended June 30, Investing Activities 2026 2025 Change (In millions) Capital investments: Distribution Segment $ 791 $ 560 $ 231 Integrated Segment 1,006 838 168 Stand-Alone Transmission Segment 750 749 1 Corporate / Other 53 86 (33) Asset removal costs 222 167 55 Other 6 14 (8) $ 2,828 $ 2,414 $ 414 Net cash used for investing activities for the first six months of 2026 increased $414 million, compared to the same period of 2025, primarily due to higher capital investments. Cash Flows From Financing Activities In the first six months of 2026 and 2025, net cash provided from financing activities was $1,783 million and $1,155 million, respectively. The following table summarizes financing activities for the first six months of 2026 and 2025: For the Six Months Ended June 30, Financing Activities 2026 2025 Change (In millions) New Issues: Unsecured convertible notes $ — $ 2,500 $ (2,500) Senior unsecured notes 1,625 1,325 300 Senior secured notes — 100 (100) FMBs 300 200 100 Term Loan 150 — 150 $ 2,075 $ 4,125 $ (2,050) Redemptions / Repayments: Unsecured convertible notes $ (294) $ (1,206) $ 912 Senior unsecured notes (375) (925) 550 Senior secured notes (25) (24) (1) $ (694) $ (2,155) $ 1,461 Short-term borrowings, net $ 1,051 $ (150) $ 1,201 Noncontrolling interest cash distributions (50) (49) (1) Common stock dividend payments (526) (502) (24) Debt issuance and redemption costs, and other (73) (114) 41 $ 1,783 $ 1,155 $ 628 71 FirstEnergy and JCP&L had the following redemptions and issuances during the six months ended June 30, 2026: Company Type Redemption / Issuance Date Interest Rate Maturity Amount (In millions) Description Redemptions FE PA Senior Unsecured March, 2026 5.15% 2026 $300 Redeemed senior unsecured notes that became due. ATSI Senior Unsecured April, 2026 4.00% 2026 $75 Redeemed senior unsecured notes that became due. FE Senior Unsecured Convertible Notes May, 2026 4.00% 2026 $294 Redeemed senior unsecured convertible notes that became due. Issuances FE PA Senior Unsecured March, 2026 4.15% 2028 $300 Proceeds were used to: (i) refinance existing indebtedness, including the repayment of FE PA's 5.15% senior notes due 2026, and short-term borrowings; (ii) to fund capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes. FE PA Senior Unsecured March, 2026 4.55% 2031 $550 Proceeds were used to: (i) refinance existing indebtedness, including the repayment of FE PA's 5.15% senior notes due 2026, and short-term borrowings; (ii) to fund capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes. MAIT Senior Unsecured April, 2026 5.02% 2036 $250 Proceeds were used to: (i) repay short-term borrowings; (ii) to finance capital expenditures; (iii) to fund working capital; and (iv) to fund other general corporate purposes. ATSI Senior Unsecured April, 2026 5.19% 2033 $175 Proceeds were used to: (i) repay short-term borrowings, including short-term borrowings incurred to repay at maturity $75 million aggregate principal amount of ATSI's 4.00% senior unsecured notes due 2026; (ii) to finance capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes. JCP&L Senior Unsecured May, 2026 4.60% 2030 $350 Proceeds were used to: (i) refinance existing indebtedness and short-term borrowings; (ii) to fund capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes. MP FMB May, 2026 4.45% 2029 $300 Proceeds were used to: (i) repay short-term borrowings; (ii) to finance capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes. PE Term Loan Facility On June 16, 2026, PE entered into a $150 million PE Term Loan Facility, with a maturity date of September 16, 2027, which was fully drawn upon execution. The PE Term Loan Facility contains covenants and other terms and conditions substantially similar to those applicable to PE under the Amended Credit Facilities and includes a requirement to maintain a debt to capitalization ratio of no more than 0.65 to 1.00, measured as of the last day of each fiscal quarter. Proceeds were used to repay short-term borrowings, to finance capital expenditures, for working capital and for other general corporate purposes. Borrowings under the PE Term Loan Facility that are Alternate Base Rate Loans (as defined in the PE Term Loan Facility) bear interest at a fluctuating interest rate per annum equal to the highest of: (i) the “prime rate” published by the Wall Street Journal from time to time, (ii) the sum of 1/2 of 1% per annum plus the federal funds rate in effect from time to time and (iii) the Term SOFR Rate for a one-month interest period plus 1%. Borrowings under the PE Term Loan Facility that are Term Benchmark Loans (as defined in the PE Term Loan Facility) bear interest at a fluctuating interest rate per annum equal to the sum of 0.70% per annum plus the Term SOFR Rate for such interest period. Borrowings under the PE Term Loan Facility that are RFR Loans (as defined in the PE Term Loan Facility) bear interest at a fluctuating interest rate per annum equal to the sum of 0.70% per annum plus Daily Simple SOFR. Borrowings under the PE Term Loan Facility are subject to acceleration upon the occurrence of events of default, including a cross-default to other indebtedness of FE in excess of $100 million and defaults for certain bankruptcy or insolvency events of FE or its significant subsidiaries. FE maintains an ordinary banking and investment banking relationship with the lender under the PE Term Loan Facility. 72 2026 Convertible Notes Issuance and Conversion: On May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, at a rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes were unsecured and unsubordinated obligations of FE, and were scheduled to mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. Proceeds from the issuance were approximately $1.48 billion, net of issuance costs. In June 2025, FE repurchased approximately $1.2 billion aggregate principal amount of the 2026 Convertible Notes, using a portion of the proceeds from the offering of the 2029 Convertible Notes and 2031 Convertible Notes described below. On May 1, 2026, FE paid approximately $325 million in cash to satisfy and settle the then-outstanding 2026 Convertible Notes, consisting of $294 million in aggregate principal amount, $6 million of accrued and unpaid interest, and approximately $25 million, representing the conversion premium paid in excess of the aggregate principal amount. 2029 Convertible Notes and 2031 Convertible Notes Issuance On June 12, 2025, FE issued $1.35 billion aggregate principal amount of its 2029 Convertible Notes, at a rate of 3.625% per year, and $1.15 billion aggregate principal amount of its 2031 Convertible Notes, at a rate of 3.875% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. The 2029 Convertible Notes and 2031 Convertible Notes are unsecured and unsubordinated obligations of FE and will mature on January 15, 2029 and January 15, 2031, respectively, unless earlier converted or repurchased in accordance with their terms. The 2029 Convertible Notes and 2031 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $2.47 billion, net of issuance costs. FE or its affiliates may, from time to time, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as FE or its affiliates may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors. JCP&L Senior Notes and Registration Rights On September 4, 2025, JCP&L issued: (i) $350 million of senior unsecured notes due in 2029; (ii) $500 million of senior unsecured notes due in 2031; and (iii) $500 million of senior unsecured notes due in 2036, in a private offering that included registration rights agreements in which JCP&L agreed to conduct an exchange offer of these senior notes for the like principal amounts registered under the Securities Act. On April 9, 2026, JCP&L filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on April 23, 2026. On June 15, 2026, JCP&L completed an exchange offer of these senior notes for like principal amounts registered under the Securities Act. In May 2026, JCP&L issued $350 million of new 4.60% Senior Unsecured Notes due in 2030 in a private offering that included a registration rights agreement in which JCP&L agreed to conduct an exchange offer of these senior notes for the like principal amounts registered under the Securities Act within 366 days after the closing. Proceeds were used to repay short-term borrowings, to finance capital expenditures, for working capital and for other general corporate purposes. On June 25, 2026, JCP&L filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on July 14, 2026, and an exchange offer was launched on July 16, 2026. FE PA Senior Notes and Registration Rights On March 19, 2026, FE PA issued $300 million of 4.15% senior unsecured notes due in 2028 and $550 million of 4.55% senior unsecured notes due in 2031, in a private offering that included registration rights agreements in which FE PA agreed to conduct an exchange offer of these senior notes for the like principal amounts registered under the Securities Act within 366 days after the closing. Shelf Registration Statement On May 29, 2026, FE filed a shelf registration statement on Form S-3 registering up to $3 billion in aggregate amount of securities, which was declared effective by the SEC on June 8, 2026. 73 FIRSTENERGY - GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications, which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of June 30, 2026, outstanding guarantees and other assurances aggregated approximately $1.1 billion, consisting of parent guarantees on behalf of its consolidated subsidiaries ($591 million) and other assurances of ($460 million). In 2025, FET, DominionHV and Transource entered into an equity support agreement to enable Valley Link to enter into a credit facility with a third party. The equity support agreement expires once all Valley Link credit agreement obligations are satisfied or when FET has fulfilled its support obligations under the equity support agreement. As of June 30, 2026, the maximum exposure of FET’s support obligations relating to the Valley Link credit facility was $102 million. Collateral and Contingent-Related Features In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2026, $210 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $42 million of net cash collateral as of June 30, 2026, from certain generation suppliers, and such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets. These credit-risk-related contingent features stipulate that if any such subsidiary were downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2026: Potential Collateral Obligations Electric Companies and Transmission Companies FE Total (In millions) Contractual obligations for additional collateral Upon downgrade $ 70 $ 1 $ 71 Surety bonds (collateralized amount)(1) 113 131 244 Total Exposure from Contractual Obligations $ 183 $ 132 $ 315 (1) Surety bonds are not tied to a credit rating. Surety bonds’ impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $20 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure. JCP&L - GUARANTEES AND OTHER ASSURANCES JCP&L has various financial and performance guarantees and indemnifications, which are issued in the normal course of business. These contracts include stand-by LOCs and surety bonds. JCP&L enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments JCP&L could be required to make under these guarantees as of June 30, 2026, was $50 million. Collateral and Contingent-Related Features In the normal course of business, JCP&L may enter into physical or financially settled contracts for the sale and purchase of electric capacity and energy. Certain agreements contain provisions that require JCP&L to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon JCP&L's credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. JCP&L has posted $30 million of collateral in the form of LOCs as of June 30, 2026. JCP&L is holding $1 million of net cash collateral as of June 30, 2026, from certain generation suppliers, and such amount is included in "Other current liabilities" on JCP&L's Balance Sheets. 74 These credit-risk-related contingent features stipulate that if JCP&L were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2026: Potential Collateral Obligations JCP&L (In millions) Contractual obligations for additional collateral Upon downgrade $ 70 Surety bonds (collateralized amount)(1) 20 Total Exposure from Contractual Obligations $ 90 (1) Surety bonds are not tied to a credit rating, and their impact assumes maximum contractual obligations, which is 100% of the face amount of the surety bond, and typical obligations require 30 days to cure. MARKET RISK INFORMATION FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Enterprise Risk Management Committee, comprised of members of senior management, provides general oversight for risk management activities throughout FirstEnergy, including market risk. Commodity Price Risk FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, coal and energy transmission. The valuation of derivative contracts is based on observable market information. As of June 30, 2026, FirstEnergy has a net asset of $17 million in non-hedge derivative contracts that are related to FTRs at certain of the Electric Companies. FTRs are subject to regulatory accounting and do not impact earnings. Equity Price Risk As of June 30, 2026, the FirstEnergy pension plan assets were allocated approximately as follows: 34% in equity securities, 20% in fixed income securities, 5% in alternatives, 8% in real estate, 22% in private debt/equity, 9% in derivatives and 2% in cash and short-term securities. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027, which, based on various assumptions, including an expected rate of return on assets of 8.0% for 2026, is expected to be approximately $250 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily. JCP&L is not expected to make a contribution to the pension plan. As of June 30, 2026, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 61% in equity securities, 36% in fixed income securities and 3% in cash and short-term securities. In the six months ended June 30, 2026, FirstEnergy’s pension plan assets have gained approximately 2.1% as compared to an annual expected return on plan assets of 8%. In the six months ended June 30, 2026, FirstEnergy’s qualified OPEB plan assets have gained approximately 8.7% as compared to an annual expected return on plan assets of 7%. FirstEnergy determines the annual expected return on plan asset assumption based on historical asset performance, target asset allocations and other economic indicators, including current market conditions and forward-looking capital market expectations, among other factors. FirstEnergy periodically evaluates target asset allocations to support long-term funding and volatility mitigation objectives, which could impact future expected return on plan asset assumptions. See Note 4., “Pension and Other Post-Employment Benefits,” of the Combined Notes to Financial Statements of the Registrants for additional details on FirstEnergy’s pension and OPEB plans. Interest Rate Risk FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets. The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension and OPEB costs for 2026, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market. 75 FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of June 30, 2026, the spot rate was 5.75% and 5.59% for pension and OPEB obligations, respectively, as compared to 5.59% and 5.37% as of December 31, 2025, respectively. The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2026. Each of the Amended Credit Facilities bears interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. Economic Conditions FirstEnergy continues to monitor supply lead times in light of demand increases across the industry, including due to data center usage, and the imposition of tariffs and retaliatory tariffs that have been, and may be, imposed by the U.S. government in response. In addition, ongoing geopolitical conflicts have contributed to volatility in global energy markets and fuel and transportation costs, which may further impact supply availability or pricing. FirstEnergy continues to implement mitigation strategies to address volatility in interest rates, inflation and supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, a prolonged continuation or further increase in demand, sustained or escalating geopolitical tensions, rising fuel costs or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition. CREDIT RISK Credit risk is the risk that the Registrants would incur a loss as a result of nonperformance by counterparties of their contractual obligations. The Registrants maintain credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. The Registrants have concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact the Registrants’ overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. The Registrants' credit policies to manage credit risk include the use of an established credit approval process and daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries, including JCP&L, may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit. OUTLOOK INCOME TAXES For federal income tax purposes, FirstEnergy files as a consolidated group, which includes JCP&L but excludes FET and its subsidiaries, and maintains an intercompany income tax allocation agreement for the allocation of consolidated tax liability, including corporate AMT. Subsequent to the closing of the FET Equity Interest Sale, FET and its subsidiaries file as their own consolidated group for federal income tax purposes and have their own intercompany income tax allocation agreement. On February 18, 2026, the U.S. Treasury and IRS issued guidance that allows certain tax repair deductions in computing corporate AMT. As a result of this guidance, FirstEnergy reversed $18 million in corporate AMT credit carryforwards in the first quarter of 2026 related to corporate AMT incurred and paid in prior tax years by both the FirstEnergy consolidated tax group and the FET consolidated tax group, none of which had an impact to the effective tax rate. Both the FirstEnergy consolidated tax group and the FET consolidated tax group remain subject to the corporate AMT, but expect that this allowance for certain tax repair deductions will reduce future corporate AMT liability. On July 4, 2025, President Trump signed into law the OBBBA, which makes permanent certain corporate tax incentives from the TCJA but which are not expected to materially impact FirstEnergy. The OBBBA also accelerates the phase out of tax credits for wind and solar projects and, accordingly, FirstEnergy is evaluating potential impacts those tax credit provisions and related IRS guidance may have on the proposed construction of solar generation facilities in West Virginia, as discussed in Note 9., “Regulatory Matters,” of the Combined Notes to Financial Statements of the Registrants. 76 During 2025, FERC issued orders to a non-affiliate concluding that, based on certain previously issued IRS private letter rulings, certain NOL carryforward deferred tax assets, as computed on a separate return basis, should be included in rate base for ratemaking purposes. FirstEnergy determined in the third quarter of 2025 that these rulings and orders also would apply to certain of its subsidiaries, resulting in a benefit from a reduction in regulatory liabilities, reflected as the remeasurement of excess deferred income taxes and an increase in accumulated deferred income tax assets for ratemaking purposes. FirstEnergy made the appropriate updates in its annual formula rates for the impacted subsidiaries. FirstEnergy will continue to monitor and evaluate future tax legislation, guidance from the U.S. Treasury and/or the IRS, including guidance related to the corporate AMT, and developments concerning the regulatory treatment of income taxes by FERC and/or applicable state regulatory authorities, that could negatively impact FirstEnergy’s and/or JCP&L’s cash flows, results of operations and financial condition. STATE REGULATION Each of the Electric Companies’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility. MARYLAND PE operates under MDPSC-approved distribution base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The EmPOWER Maryland program, following passage of the Climate Solutions Now Act of 2022, required annual incremental energy efficiency targets of 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. However, the GHG emission reduction targets for electric companies were amended by the Utility RELIEF Act, which temporarily lowered said targets from 2.5% per year to 1.75% for each year for the 2027-2029 program cycle, 2% for each year for the 2030-2032 program cycle, and 2.25% for each year for the 2033-2035 program cycle. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC and later, at the direction of the MDPSC, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million, which the MDPSC approved on December 27, 2024. PE previously recovered EmPOWER Maryland program costs with carrying costs on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Consistent with an MDPSC order dated December 29, 2022, phasing out the unamortized balances of EmPOWER Maryland investments, PE is required to expense 100% of its EmPOWER Maryland program costs in 2026 and beyond. All previously unamortized costs for prior cycles are to be collected by the end of 2030, consistent with the 2024-2026 order issued on December 29, 2023. Lost distribution revenue attributable to energy efficiency or demand reduction is recovered only through base rates. Legislation that took effect on July 1, 2024, was estimated to reduce the carrying costs on the EmPOWER Maryland unamortized balances for PE by a total of $25 to $30 million over the period of 2024-2030. On July 31, 2024, the MDPSC issued an order implementing revised EmPOWER Maryland surcharge rates for PE in accordance with the new law, denying PE’s request for a hearing that sought to challenge certain portions of the law. On August 30, 2024, PE filed a petition seeking judicial review of its challenge to the law in the Circuit Court for Washington County, Maryland. On August 6, 2025, the Circuit Court for Washington County, Maryland issued an order granting PE’s petition, finding that the legislature may not change terms to apply retroactively to monies already expended. MDPSC and the Maryland Office of People’s Counsel have each appealed the decision. On November 14, 2025, the Appellate Court of Maryland issued an order denying the unopposed motion of the Attorney General of Maryland to intervene without prejudice to the ability to file an amicus curiae brief, which the Attorney General filed on December 30, 2025. PE's response brief was filed on January 21, 2026. NEW JERSEY JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party 77 EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. In 2021, JCP&L, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US LLC and EDF Renewables North America, proposed transmission upgrades to connect offshore wind-generated electricity to the New Jersey power grid. The NJBPU approved portions of the proposal on October 26, 2022, authorizing approximately $723 million of transmission investments and providing JCP&L the option to acquire up to a 20% equity interest in Mid-Atlantic Offshore Development, LLC. On August 22, 2023, FERC approved an abandonment incentive that allowed recovery of certain prudently incurred project costs if the project were cancelled for reasons beyond JCP&L’s control. Beginning in late 2023, major offshore wind developments in New Jersey were cancelled or abandoned. In response to these developments, JCP&L sought guidance from the NJBPU in 2025 regarding project scheduling while continuing to meet its contractual obligations. In August 2025, the NJBPU directed JCP&L to defer certain transmission investments for approximately 2.5 years and directed JCP&L to work with NJBPU staff and PJM to ensure alignment as to the work that is to be continued on the original timeline and the work that is to be delayed consistent with the order. Capital investments in the transmission projects totaled approximately $200 million as of June 30, 2026. On April 22, 2026, the NJBPU issued an order finding that, among other things, continued investment in certain of the transmission infrastructure to connect off-shore wind generated electricity to the grid is not in the best interest of the state or its ratepayers. In the order, the NJBPU authorized execution of an agreement with PJM to terminate the identified transmission projects, which it filed at FERC on April 23, 2026. The agreement included provisions to the effect that New Jersey’s ratepayers will remain responsible for JCP&L’s prudently incurred costs for the affected projects and a request for approval by June 23, 2026. On May 14, 2026, JCP&L filed supportive comments at FERC. On June 22, 2026, FERC accepted the termination agreement. On July 2, 2026, PJM notified JCP&L that PJM had terminated the agreements that obligated JCP&L to construct the identified projects. JCP&L expects to file an application for FERC authorization to recover the abandoned project costs. In February 2025, the NJBPU certified the results of its annual basic generation service auctions through which New Jersey’s four EDCs – including JCP&L – satisfy their generation supply requirements for BGS customers for the period beginning June 1, 2025 through May 31, 2026. The certified results resulted in significant rate increases for New Jersey EDC customers and, by order dated April 23, 2025, the NJBPU directed the four EDCs to submit proposals to mitigate the impact of the rate increases that affected residential customers beginning June 1, 2025. On May 7, 2025, JCP&L filed a petition in response to the April 2025 order, modeling four potential mitigation scenarios. On June 18, 2025, the NJBPU approved a stipulation that included JCP&L, NJBPU staff and New Jersey Division of Rate Counsel, pursuant to which, among other things, JCP&L agreed to apply a temporary rate credit of $30.00 to each residential electric customer’s monthly bill in July and August 2025 that would be deferred in a regulatory asset and recovered with a charge of $10 applied to each residential bill from September 2025 through February 2026 to recover the amounts deferred, without carry charges, subject to a final reconciliation. As of June 30, 2026, JCP&L has fully recovered the regulatory asset associated with the temporary rate credits. On August 13, 2025, the NJBPU issued an Order to Show Cause reviewing JCP&L’s 2024 Annual System Performance Report, which includes information regarding JCP&L’s systems level of electric service reliability performance during the prior calendar year. Failure to attain NJBPU’s minimum reliability levels may subject JCP&L to a penalty. The NJBPU order alleges JCP&L has failed to achieve minimum reliability levels for calendar years 2022, 2023, and 2024, and directed JCP&L to file an answer demonstrating why the NJBPU should not impose certain penalties upon JCP&L for such failure, which JCP&L filed on October 10, 2025. On April 13, 2026, NJBPU staff issued a letter to JCP&L stating its intention to recommend that the NJBPU impose a penalty against JCP&L in the amount of $44 million, while also requesting a meeting with JCP&L to discuss the potential penalty recommendation and a possible resolution. On April 16, 2026, JCP&L responded in writing to the NJBPU staff welcoming the opportunity to discuss with NJBPU staff and disputing the magnitude of the recommended penalty and questioning the approach taken by NJBPU staff. JCP&L is engaged in settlement discussions with the parties and had a meeting with the NJBPU staff on July 17, 2026. JCP&L believes it is probable that it will incur a loss, but based on the status of the settlement discussions is unable to estimate the amount of any penalty and/or predict other actions that may be imposed by the NJBPU. On January 14, 2026, the NJBPU issued an order authorizing JCP&L to modify its Lost Revenue Adjustment Mechanism rate rider in its tariff. The modification allows JCP&L to recover the revenue impact of sales losses of approximately $16 million (pre-tax) primarily resulting from the implementation of JCP&L’s Energy Efficiency and Conservation Plan during the one-year period from July 1, 2023, through June 30, 2024. The modification was effective February 1, 2026. On May 21, 2026, the NJBPU issued an order concluding that certain nuclear generating units participating in the state’s ZEC program received duplicate compensation during 2024, and directed the owners of the affected generating units to refund the duplicate payments, with applicable interest, to the affected EDCs, including JCP&L. The order further directed that the refunded amounts be returned to customers through reinstated ZEC tariffs beginning June 1, 2026. On May 26, 2026, JCP&L received payment in the amount of $82 million. Also on May 26, 2026, JCP&L made the requisite compliance filing with the NJBPU requesting restoration of its ZEC tariff effective June 1, 2026, and began issuing customer refunds. Refunds are expected to continue through May 31, 2027, or until such time as the refunded balance is exhausted. As of June 30, 2026, JCP&L's regulatory liability associated with these amounts to be refunded to customers was approximately $80 million. 78 OHIO The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. From June 1, 2024, until January 31, 2025, the Ohio Companies operated under ESP V, as modified by the PUCO, and as further described below. On December 18, 2024, the PUCO approved the Ohio Companies’ notice to withdraw ESP V and approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. ESP IV, as modified, continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with an annual revenue cap of $390 million. In addition, ESP IV, as modified, includes a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and contributions, totaling $6.39 million per year, to: (a) fund energy conservation, economic development and job retention programs in the Ohio Companies’ service territories; and (b) establish fuel-funds in each of the Ohio Companies’ service territories to assist low-income customers. On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which became effective June 1, 2024, and would have continued through May 31, 2029. The Ohio Companies filed an application for rehearing challenging various aspects of the May 15, 2024, order, but due to the risks and uncertainty resulting from the Ohio Companies’ application for rehearing being denied by operation of law, on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. On December 18, 2024, the PUCO approved the Ohio Companies’ notice of withdrawal. Also on December 18, 2024, the PUCO approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. Consistent with ESP IV, the PUCO authorized the Ohio Companies’ reinstatement of the DCR rider. Additionally, the PUCO ordered that storm costs deferred under ESP V since June 1, 2024, remain on the Ohio Companies’ books and subject to review in a future case. On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV. On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV. On May 22, 2025, the Ohio Supreme Court granted the Ohio Companies’ motion to intervene in the appeal. On July 7, 2025, OCC and NOAC filed their Appellants’ brief. Appellees, including the PUCO and the Ohio Companies, filed their briefs on August 26, 2025, to which OCC and NOAC replied on September 15, 2025. On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI. On May 15, 2025, the Ohio Governor signed HB 15, which repealed the statute authorizing ESPs in Ohio, effective August 14, 2025. On December 17, 2025, the PUCO dismissed the Ohio Companies’ application for ESP VI due to the repeal of the ESP statute. On March 14, 2025, as directed by the PUCO in its December 18, 2024, order approving the Ohio Companies’ revised ESP IV tariffs, the Ohio Companies filed with the PUCO a request to commence their statutorily required quadrennial review of ESP IV and establish a proposed schedule. On July 10, 2025, the Ohio Companies withdrew the request for the PUCO to establish a procedural schedule following the May 15, 2025, signing by the Ohio Governor of HB 15 ending the statutory mandate to conduct the quadrennial review, effective August 14, 2025. The OCC filed its response to the Ohio Companies’ notice of withdrawal on July 25, 2025, to which the Ohio Companies replied on August 1, 2025. The matter remains pending before the PUCO. On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. On November 19, 2025, the PUCO issued an order in the rate case lifting the rate freeze and approving a net increase in base distribution revenues of the Ohio Companies of approximately $34 million, with a return on equity of 9.63% and a hypothetical capital structure of 48.8% debt and 51.2% equity for all three Ohio Companies, which reflects a roll-in of current riders such as DCR and AMI. The PUCO authorized continuance of Rider DCR with a cap increase commensurate with capital investments through January 31, 2025, and approved the Ohio Companies’ proposal to change pension and OPEB recovery to the delayed recognition method. Additionally, the order authorizes recovery of certain deferred costs for storm restoration, operations and maintenance, and energy efficiency programs. As a result of the order, the Ohio Companies recognized a $352 million pre-tax impairment charge related to future recovery disallowances of certain previously capitalized amounts. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025, base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On February 18, 2026, the PUCO issued an entry on rehearing, which extended the amortization period for recovery of deferred storm restoration costs from five years to twenty-five years, subject to prudency review, and clarified the amount of the authorized increase in Rider DCR revenue caps is $14 million, subject to the Ohio Companies meeting reliability standards. With these adjustments, the rate case’s outcome is a net decrease in base distribution revenues of the Ohio Companies of approximately $5 million. The entry further ordered the Ohio Companies to file revised final tariffs and approved the Ohio Companies’ compliance tariffs, effective March 1, 2026. On March 20, 2026, the Ohio Companies and certain other parties filed with the PUCO second applications for rehearing of the February 18, 2026, entry on rehearing. On April 14, 2026, the PUCO issued an entry on rehearing denying all applications for rehearing. On May 14, 2026, Retail Energy Supply Association and IGS Energy Supply, LLC jointly filed with the PUCO a request for clarification and application for rehearing, to which the OCC and the Ohio Companies responded on May 26, 2026. On June 10, 2026, the PUCO issued its Fourth Entry on Rehearing, denying the application for rehearing. Following the PUCO’s final decision, parties have a 60-day window to appeal to the Supreme Court of Ohio. 79 On May 16, 2022, May 15, 2023, and May 15, 2024, the Ohio Companies filed their SEET applications for determination of the existence of significantly excessive earnings under ESP IV for calendar years 2021, 2022, and 2023, respectively. On May 15, 2025, the Ohio Companies filed their SEET application for determination of the existence of significantly excessive earnings under ESPs IV and V for calendar year 2024. Each application demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On May 11, 2026, the Attorney Examiner issued an entry consolidating the SEET proceedings for calendar years 2021 through 2024. On July 21, 2026, the Ohio Companies and the PUCO staff entered into a settlement, unopposed by OCC, stipulating that the Ohio Companies did not have significantly excessive earnings in 2021, 2022, 2023 or 2024. An evidentiary hearing has been scheduled for August 11, 2026. On January 7, 2026, the PUCO issued an order, which directed the Ohio Companies to pay their customers, among other things, restitution and refunds totaling approximately $275 million ($213 million after-tax), which was recognized in the fourth quarter of 2025. The restitution and refunds are being provided to customers over three billing cycles, which began in February 2026. As of June 30, 2026, the Ohio Companies have issued approximately $266 million in restitution and refunds. On May 22, 2026, the Ohio Companies filed with the PUCO a three-year rate plan, requesting approval of three consecutive, annual test periods that begin July 1, 2027 and end June 30, 2030. The application proposes a net increase in the Ohio Companies’ base distribution revenues of approximately $254 million in the first year, approximately $59 million in the second year, and approximately $80 million in the third year, with a return on equity of 10.2% and a capital structure of approximately 47% debt and approximately 53% equity for all three Ohio Companies. On June 12, 2026, PUCO staff issued a deficiency letter requesting additional supplementation in certain areas, which the Ohio Companies provided on June 22, 2026. On July 1, 2026, an administrative law judge deemed the application complete and set a procedural schedule. Evidentiary hearings are set to begin March 1, 2027. See below for additional details on the ongoing government investigations and ongoing litigation surrounding HB 6. PENNSYLVANIA FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025. FE PA operates under rates approved by the PPUC, effective as of January 1, 2025. FE PA operates under a DSP through the May 31, 2027 delivery period, which provides for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021, through May 31, 2026, was approved by the PPUC on June 18, 2020, providing cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district. On November 26, 2025, FE PA submitted a petition for approval of its Phase V Energy Efficiency and Conservation Plan, which includes energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.01% MW, and energy consumption reduction targets, as a percentage of FE PA’s historic 2009 to 2010 reference load, at 2.00% MWh. The proposed plan includes cost recovery of approximately $390 million to be recovered through its Phase V Energy Efficiency and Conservation Charge Rider and runs for a five-year period beginning June 1, 2026, through May 31, 2031. Hearings were held on January 29, 2026. The parties reached a full settlement in principle and filed with the PPUC a Joint Petition for Complete Settlement on February 19, 2026. On March 12, 2026, the PPUC issued an order approving the settlement with limited modifications requiring FE PA to file revisions to the plan, which were filed on April 15, 2026. On February 3, 2026, FE PA filed a proposed DSP for provision of generation for the June 1, 2027 through May 31, 2031 delivery period, to be sourced through competitive procurements for customers who do not receive service from an alternative EGS. Under this DSP, supply would be provided through a mix of 12, 24, and in the case of residential customers, 60-month energy contracts, as well as spot market purchases for industrial customers. A hearing was held on June 15, 2026. FE PA reached a comprehensive settlement with certain parties and was filed with the PPUC on July 2, 2026. A final order is expected from the PPUC in the fourth quarter of 2026. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective March 27, 2024, and, for applicable customers, a WVPSC-approved solar surcharge that was most recently adjusted effective January 15, 2026. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s 80 ENEC rate is typically updated annually and MP and PE filed their ENEC filing on August 29, 2025, for rates effective January 1, 2026. During the first quarter of 2026, MP and PE incurred significant PJM charges during the Winter Storm Fern weather event totaling $145 million, which were deferred for future recovery as part of the ENEC. On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. Two of the five solar generation sites went into service in 2024, with the third in April 2025. On August 29, 2025, MP and PE filed with the WVPSC their biennial review of their vegetation management program and surcharge. MP and PE have proposed an approximate $3.2 million decrease in the surcharge rates due to an over-recovery balance as of June 30, 2025, and higher costs for fuel and reagents. The WVPSC held a hearing regarding rate matters on December 15, 2025. The WVPSC issued an order on March 26, 2026, approving the MP and PE vegetation management program and granting rate recovery for its costs. On October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC. To ensure that MP and PE can meet their PJM adequacy requirements, the plan proposes, among other things, near-term market capacity purchases and the addition of 70 MWs of solar generation by 2028 and 1,200 MWs of natural gas combined cycle generation by 2031. On May 6, 2026, an evidentiary hearing was held. On February 13, 2026, MP and PE filed a CPCN to construct and operate the 1,200 MW combined cycle gas turbine plant, that will be known as Maidsville Energy Center, and the 70 MWs of solar generation capacity, each referenced in their integrated resource plan above, for an estimated capital investment totaling approximately $2.7 billion as of the date of the filing. The request also includes a surcharge designed to recover financing costs during development and construction of the projects, as well as to transition to recovery in base rates once the projects are placed in-service and approved through a base rate case. Evidentiary hearings were held on July 16 and 17, 2026. A final order is expected from the WVPSC in the second half of 2026. On May 15, 2026, MP and PE filed a base rate proceeding proposing an increase in electric rates of $188.4 million, an approximate 10.6% increase in total revenues. The filing includes a base rate increase of $174.6 million and a proposed reliability program and surcharge of $13.8 million. As an alternative, MP and PE requested a phased approach of two increases of $37.9 million effective August 1, 2026, and $37.6 million effective June 1, 2027, with a commitment to abstain from filing another base rate case until April 1, 2028. On June 11, 2026, the WVPSC staff filed a motion to dismiss, which the WVPSC denied on July 2, 2026. The WVPSC held a hearing on the alternative two-phase approach on July 9, 2026. An order is expected from the WVPSC by the end of July 2026. If approved as proposed, new rates associated with the first phase would become effective in August 2026. FERC REGULATORY MATTERS Under the FPA, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM, and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although, in the case of the Electric Companies, major wholesale purchases remain subject to review and regulation by the relevant state commissions. The Electric Companies and AE Supply are required to renew their respective authorizations every three years, and on December 16, 2025, the companies filed applications for the next renewal period. Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in material compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of 81 isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows. Transmission ROE Incentive On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliate and American Electric Power Service Corporation, and Duke Energy Ohio, Inc. asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke Energy Ohio, Inc., but granted it as to AEP’s Ohio affiliate. AEP’s Ohio affiliate and OCC appealed FERC’s orders to the Sixth Circuit. On January 17, 2025, the Sixth Circuit ruled that the 50 basis point adder is available only where RTO membership is voluntary, that Ohio law requires Ohio’s transmission utilities to be members of an RTO, and that it was unlawful for FERC to excise the adder from AEP’s Ohio affiliate rates, but not from the Duke Energy Ohio, Inc. and ATSI rates. During 2024, as a result of the ruling, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the FirstEnergy Consolidated Statements of Income and Comprehensive Income at the Stand-Alone Transmission segment, to reflect the expected refund owed to transmission customers back to February 24, 2022. On June 20, 2025, and June 24, 2025, ATSI and AEP’s Ohio affiliate, respectively, applied for the Supreme Court of the U.S. to review the Sixth Circuit’s decision. On November 10, 2025, the Supreme Court of the U.S. denied ATSI’s petition for the court to review the case. On November 13, 2025, the Sixth Circuit issued a mandate sending the case back to FERC for further proceedings. On June 25, 2026, FERC issued an order on remand directing ATSI to submit a compliance filing within 30 days to remove the RTO incentive and make refunds with interest within 30 days for the period beginning February 24, 2022, through the date of the refund. On July 22, 2026, FERC approved ATSI’s subsequent request to defer the deadline to issue refunds until February 28, 2027, in order to accommodate the PJM and MISO processes for processing refunds as directed by FERC’s order. On July 27, 2026, ATSI submitted to FERC a filing to amend its formula rate to remove on a going-forward basis 50 basis points of authorized earnings in compliance with FERC’s orders. As of June 30, 2026, ATSI’s estimated refund obligation, including interest, totaled approximately $79 million, which is recorded in “Regulatory liabilities” on FirstEnergy’s Consolidated Balance Sheets. Transmission ROE Methodology A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 and remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis; provided however, due to the Sixth Circuit’s ruling in the Transmission ROE Incentive matter described above, ATSI is collecting the ROE incentive adder subject to refund. Transmission Planning Supplemental Projects On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. Subsequently, intervenors expanded the scope of this proceeding to all of the transmission utilities in PJM, including JCP&L. ATSI and the other transmission utilities in Ohio and PJM filed comments. Local Transmission Planning Complaint On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates. The complaint demands that FERC: (i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100 kV or higher; (ii) appoint “independent transmission monitors” to conduct such planning; and (iii) condition construction of local transmission facilities on the facility 82 having been planned by the “independent transmission monitor.” FirstEnergy is participating in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. FirstEnergy, together with the PJM transmission owners, filed a motion to dismiss the complaint on March 20, 2025, which is pending before FERC. FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy and its transmission capital investment strategy. Ghiorzi v. PJM In December 2023, PJM assigned certain baseline RTEP projects to NextEra Energy Transmission, which subsequently informed PJM that it would not construct the projects. On April 3, 2025, following the reassignment by PJM of certain baseline RTEP projects in Maryland and Virginia to PE, two individuals filed a complaint at FERC challenging this outcome, which FERC denied on February 2, 2026. The complainants asserted that PJM erred in reassigning the work to PE because such reassignment projects: (i) did not reflect the cost estimates or cost caps included in NextEra Energy Transmission’s bid; and (ii) would be constructed with different routing than originally proposed. On February 2, 2026, FERC denied the complaint and on April 3, 2026, FERC denied the rehearing request filed by the complainants on March 4, 2026. On June 22, 2026, FERC affirmed its February 2, 2026, order denying the complaint. FirstEnergy and PE are unable to predict the outcome or estimate the impact that this complaint may have. Abandonment Transmission Rate Incentive On February 26, 2025, PJM completed its 2024 RTEP Open Window 1 process and, among other actions, designated each of ATSI and PE to construct certain transmission projects. On July 11, 2025, ATSI and PE filed a joint application for the abandonment incentive with FERC, which was approved on September 9, 2025. Effective September 10, 2025, ATSI and PE each became eligible to recover 50% of the project costs incurred prior to September 10, 2025, and 100% of the project costs incurred thereafter for any projects subsequently cancelled for reasons beyond the control of utility management. PJM Capacity Market Reforms On January 16, 2026, the Trump administration and the governors of all thirteen PJM states released a Statement of Principles Regarding PJM. This Statement of Principles is designed to, among other things, increase capacity available in the PJM market. PJM sought input from its stakeholders on matters related to the Statement of Principles, including: (i) proposals for a backstop capacity auction, price (cap), term, and quantity; (ii) on whether to extend the existing capacity auction price collar; and (iii) accelerating large load interconnections bringing their own generation. On July 27, 2026, the PJM Board of Managers announced its plans to procure up to 6,800 MW of capacity resources; the costs of which will be allocated to load-serving entities. PJM is expected to file its proposal with FERC on July 31, 2026, and, subject to FERC approval, to conduct the procurement in the fourth quarter of 2026. FirstEnergy is continuing to participate in the PJM stakeholder processes and will participate in the FERC proceedings. Large Load Interconnection Rulemaking On October 23, 2025, the U.S. Secretary of Energy directed FERC to conduct a rulemaking procedure to develop regulations that would speed interconnection to the transmission system of large loads, including AI data centers and “hybrid” data center/electric generation facilities. The U.S. Secretary of Energy advanced 14 principles to guide this outcome, including that such large loads should be responsible for paying the costs of any network transmission system upgrades required for interconnection of such large loads. The U.S. Secretary of Energy requested that FERC take final action by April 30, 2026. On October 27, 2025, FERC noticed the U.S. Secretary of Energy’s directive for comment, and subsequently established November 21, 2025, as the deadline for initial comments and December 5, 2025, as the deadline for reply comments. FET and its transmission affiliates, as well as over 150 other parties, filed comments. On June 18, 2026, FERC established a “show cause” proceeding for PJM and the PJM transmission owners, while also establishing similar dockets for each of the other RTOs and ISOs and their respective transmission owners. FERC is using the “show cause” proceeding as a means for the affected transmission owners to submit tariff revisions to address the requirements needed to interconnect and serve customers seeking transmission service on behalf of large loads. PJM and the PJM transmission owners are required to submit an initial compliance filing with FERC by August 17, 2026, unless PJM and the PJM transmission owners notify FERC by August 3, 2026, that they plan to implement FERC’s directives by means of tariff amendments pursuant to FPA Section 205, in which case the compliance filing is due on November 16, 2026. FirstEnergy is unable to predict the outcome of this proceeding. Utility RELIEF Act and Related FERC Complaint The Utility RELIEF Act, which became effective July 1, 2026, requires all transmission utilities within Maryland to participate as members in an RTO. On July 2, 2026, the Maryland Energy Administration, MDOPC, and MDPSC filed a complaint at FERC against PE, Valley Link Maryland, and all other Maryland transmission owners. The complaint seeks a FERC order directing the Maryland transmission owners to remove the RTO 50 bps ROE adder incentive from each of their transmission rates. The Maryland Energy Administration, MDOPC, and MDPSC seek to apply FERC’s rulings that remove the RTO incentive from transmission rates when state laws require RTO participation. The complaint requested that any RTO incentive adders collected after July 1, 2026, be refunded. The deadline for responding to the complaint is August 5, 2026. 83 ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate the Registrants regarding air and water quality, hazardous and solid waste management and disposal, and other environmental matters. While the Registrants’ environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. The Registrants cannot predict changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions that may evolve. On March 12, 2025, the EPA announced its intent to reevaluate or reconsider numerous environmental regulations, many of which apply to the Registrants. The final outcome of this initiative remains unknown, but regular required rulemaking processes and procedures still apply, and, as anticipated, litigation has occurred. The disclosures herein do not attempt to discern potential impacts of these deregulatory actions until and unless formal rulemaking or other regulatory actions are announced and the potential impacts to operations can be discerned. The disclosures below apply to FirstEnergy and the disclosures under “Regulation of Waste Disposal,” are also applicable to JCP&L. Clean Air Act FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between electric generation facilities located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from electric generation facilities in 13 states, including West Virginia. This followed the 2014 Supreme Court of the U.S. ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from electric generation facilities in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone NAAQS. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the Supreme Court of the U.S. Oral argument was heard on February 21, 2024. On June 27, 2024, the Supreme Court of the U.S. granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. On February 6, 2025, the EPA filed a motion at the D.C. Circuit to hold the proceedings in abeyance for 60 days to allow the EPA time to familiarize itself with the Good Neighbor Plan and in particular, time to brief the new administration about these consolidated petitions and the underlying Rule to allow the EPA to decide what action, if any, is necessary. On March 10, 2025, the EPA filed a motion for remand with the D.C. Circuit identifying issues with the Good Neighbor Plan that make reconsideration appropriate. The D.C. Circuit granted the motion for remand and cancelled oral argument. Consistent with its March 12, 2025, announcement, the EPA intends to undertake reconsideration of the rule and complete any new rulemaking by the fourth quarter of 2026. On January 27, 2026, the EPA proposed phase 1 of its reconsideration of the rule applicable to eight states outside of FirstEnergy’s service area. FirstEnergy 84 will continue to monitor any further actions by the EPA for any potential impact to its business and results of operations. Climate Change In recent years, certain regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. At the federal level, presidential administrations have held differing views on prioritizing actions to address GHG emissions and, by extension, climate change. Those differing views have led to policy changes, creating uncertainty about environmental requirements and associated impacts. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” known as the 2009 Endangerment Finding, concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generation facilities. The 2009 Endangerment Finding is the basis of the EPA’s authority to regulate GHG emissions under the CAA. In January 2025, Executive Order 14514 was issued and, among other deregulatory actions, directed the EPA Administrator to make recommendations on the “legality and continuing applicability” of the EPA’s 2009 Endangerment Finding, which forms the basis for the EPA's GHG regulations. On March 12, 2025, the EPA announced a series of planned deregulatory actions that it would be taking related to such executive order, including reconsideration of the regulations to limit power plant GHG emissions. On July 29, 2025, the EPA announced a proposal to rescind its 2009 Endangerment Finding. On February 12, 2026, the EPA issued a final rule rescinding its 2009 Endangerment Finding, thereby eliminating the basis for much of the EPA’s regulation of GHG emissions. On February 18, 2026, the first of several petitions for review were filed at the D.C. Circuit challenging the rescission by the EPA. Depending on the outcome of these appeals and any future EPA actions, compliance with the GHG emissions limits could require additional capital expenditures or changes in operation at the Fort Martin and Harrison power stations. On May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. On April 25, 2024, the EPA issued a final rule, which we refer to as the GHG rule, that imposed stringent GHG emissions limitations on power plants based on fuel type and unit retirement date. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which include MP as a member, filed petitions for review of the GHG rule in the D.C. Circuit. The D.C. Circuit subsequently granted a motion from the EPA placing the litigation in abeyance until further order of the Court. On June 17, 2025, the EPA published a proposed rule to repeal the GHG rule. This proposal to repeal the GHG rule remains under active consideration by the EPA. If and when finalized, the EPA’s repeal of the GHG rule is expected to be challenged in federal court. Although FirstEnergy continues to evaluate the impact of federal GHG regulations on its operations, it cannot predict the outcome of any regulatory actions or the result of potential litigation challenging any of these actions. At the state level, there are several initiatives to reduce GHG emissions. Certain northeastern states are participating in the RGGI and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). FirstEnergy’s ability to achieve its GHG reduction goal is subject to its ability to make operational changes and is conditioned upon numerous risks, many of which are outside of its control. With respect to FirstEnergy’s coal-fired facilities in West Virginia, which serve as the primary source of its Scope 1 emissions, it has identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. MP filed its 10-year integrated resource plan with the WVPSC on October 1, 2025, which highlighted, among other things, the need for new dispatchable generation in West Virginia. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If FirstEnergy is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s financial condition, results of operations, and cash flow. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. FirstEnergy continues to monitor climate change policies at both the federal and state level. Based on the EPA’s final rule rescinding the 2009 Endangerment Finding and other anticipated rulemaking, we may experience a reduction in GHG reporting and other regulatory obligations at the federal level over the near term. Multiple lawsuits opposing the EPA’s rescission were filed after it was finalized and the legal conflict is expected to be extensive. In light of the pending legal challenges, FirstEnergy is unable to predict the impact on its business and operations. 85 Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits were renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025, for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired electric generation facilities that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the U.S. Court of Appeals for the Fifth and Eighth Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the rule pending disposition on the merits. A number of other parties have challenged the final rule in various petitions for review across several circuits. Those petitions and motions for stay have been consolidated in the U.S. Court of Appeals for the Eighth Circuit. On October 10, 2024, the U.S. Court of Appeals for the Eighth Circuit denied the motions for stay. Depending on the outcome of appeals and the EPA’s review, compliance with the 2024 ELG rule could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. On February 19, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the U.S. Court of Appeals for the Eighth Circuit, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. On February 28, 2025, the U.S. Court of Appeals for the Eighth Circuit granted the EPA’s motion. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the 2024 ELG rule. On December 31, 2025, the EPA published a final ELG Deadline Extensions Rule extending certain compliance deadlines included in the 2024 ELG Rule by five years. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generation facilities. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025, with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. As of June 30, 2026, AE Supply has made cumulative cash payments of $68 million to the escrow account since the transfer in 2025. On May 8, 2024, the EPA issued the legacy CCR rule, which finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. On February 13, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation, which was filed on August 8, 2024, by the Utility Solid Waste Act Group with FE as a member, in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed, which the D.C. Circuit granted. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the final legacy CCR rule. FirstEnergy continues to monitor the EPA’s actions related to CCR regulations; however, the ultimate impact is unknown at this time and is subject to the outcome of the litigation and any future state regulatory actions. Depending on the outcome of appeals and the EPA’s rule, compliance with the final legacy CCR rule could require remedial actions, including removal of coal ash. Certain of the FirstEnergy companies have been named as potentially responsible parties at waste disposal sites, which may 86 require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of June 30, 2026, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $92 million ($74 million at JCP&L) have been accrued through June 30, 2026, of which approximately $66 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS U.S. v. Larry Householder, et al. On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences; the Sixth Circuit recently rejected their appeal upholding their convictions. Also, on July 21, 2020, and in connection with the U.S. Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District of Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. On January 17, 2025, the U.S. Attorney’s Office announced that a federal grand jury charged two former FirstEnergy senior officers with one count of participating in a Racketeer Influenced and Corrupt Organizations Act conspiracy. The allegations in the indictment are largely based on the conduct described in the DPA. On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter as to FE. Under the DPA, FE agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA required that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, consisting of (x) $115 million paid by FE to the U.S. Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates nor charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as an expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 22, 2024, FirstEnergy had successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue: (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S. Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the aforementioned federal indictment against two former FirstEnergy senior officers. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information. On February 26, 2025, the U.S. Attorney’s Office filed a status report confirming these commitments. Legal Proceedings Relating to U.S. v. Larry Householder, et al. Certain FE stockholders and FirstEnergy customers also filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits are related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). •In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020, and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017, and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by making alleged misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 87 12(a)(2) and 15 of the Securities Act as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the Sixth Circuit seeking to appeal that order. On August 13, 2025, the Sixth Circuit vacated the S.D. Ohio’s order granting class certification. On November 6, 2025, the S.D. Ohio held oral argument to further consider class certification in light of the Sixth Circuit’s decision. On April 30, 2026, the S.D. Ohio issued an order recertifying plaintiffs’ proposed class. FE filed a petition in the Sixth Circuit to appeal that order on May 14, 2026. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss. •MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio); on December 17, 2021, and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain then-current and former officers of Energy Harbor Corp. The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by making alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss. The outcome of any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows. NEW ACCOUNTING PRONOUNCEMENTS See Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants for a discussion of new accounting pronouncements. 88 JERSEY CENTRAL POWER & LIGHT COMPANY MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS JCP&L is a wholly owned subsidiary of FE. JCP&L conducts business in New Jersey by providing regulated electric transmission and distribution services in northern, western and east central New Jersey, representing $5.1 billion in rate base as of December 31, 2025. JCP&L is subject to regulation by the NJBPU and FERC. JCP&L distributes electricity to approximately 1.2 million customers in New Jersey across its distribution footprint. JCP&L owns and operates transmission infrastructure that is used to transmit electricity, with revenues derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which are subject to an annual true-up based on actual rate base and costs. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU. JCP&L’s results reflect the costs of securing and delivering electric generation to customers and net transmission expenses related to the delivery of electricity on JCP&L’s transmission facilities, including the deferral and amortization of certain costs. As discussed in Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants, during the fourth quarter of 2025, JCP&L identified an error in the recording of certain expenses for smart meter cost of removal associated with the deployment of its AMI program, resulting in an understatement of expense on the Statements of Income and Comprehensive Income and Regulatory assets/liabilities on the Balance Sheets since 2023. JCP&L evaluated the error, and the specific impact on each affected prior period was not material, however, as a result of the cumulative impact, JCP&L determined it should revise previously issued financial statements to correct the error and, in doing so, also corrected other immaterial errors. As such, JCP&L has revised the previously issued interim Results of Operations for the three and six months ended June 30, 2025. As of January 1, 2026, JCP&L made changes in how management evaluates operating performance and allocates resources. As a result of these changes, JCP&L reassessed its operating segments and determined that its operations are now managed as a single integrated business. Historically, JCP&L reported two operating segments, Distribution and Transmission. Accordingly, JCP&L changed its external segment reporting to present its results, including comparative periods, as a single reportable segment for the first six months of 2026, and reclassified prior periods for comparability. There are no changes to JCP&L’s significant expenses, measure of profit or loss, or other segment items. For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Executive Summary and Recent Developments, Regulatory Assets and Liabilities, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Pronouncements. 89 JCP&L Summary of Results of Operations—Second Quarter 2026 Compared with Second Quarter 2025 JCP&L’s financial results for the three months ended June 30, 2026, and 2025, were as follows: Second Quarter 2026 Financial Results For the Three Months Ended June 30, (In millions) 2026 2025 (1) Change Revenues $ 659 $ 592 $ 67 Operating Expenses: Purchased power 349 303 46 Other operating expenses 194 137 57 Provision for depreciation 63 65 (2) Amortization of regulatory assets, net (76) (12) (64) General taxes 6 6 — Total operating expenses 536 499 37 Other Income (Expense): Miscellaneous income (expense), net 13 11 2 Interest expense - other (41) (30) (11) Interest expense - affiliates (3) (2) (1) Capitalized financing costs 13 10 3 Total other expense (18) (11) (7) Income taxes 26 20 6 Net Income $ 79 $ 62 $ 17 (1) Previously issued 2025 JCP&L amounts have been revised due to the correction of immaterial errors as discussed in Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants. Distribution services by customer class are summarized in the following table: For the Three Months Ended June 30, (In thousands) Actual Weather-Adjusted Electric Distribution MWh Deliveries 2026 2025 Increase (Decrease) 2026 2025 (Decrease) Residential 2,269 2,216 2.4 % 2,076 2,096 (1.0) % Commercial(1) 2,016 2,047 (1.5) % 1,961 2,020 (2.9) % Industrial 421 428 (1.6) % 421 428 (1.6) % Total Electric Distribution MWh Deliveries 4,706 4,691 0.3 % 4,458 4,544 (1.9) % (1) Includes street lighting. Distribution deliveries for the residential and commercial customer classes were impacted by the weather temperatures. Heating degree days in the second quarter of 2026 were 23% above the same period of 2025 and 1% below normal. Cooling degree days in the second quarter of 2026 were 20% above the same period of 2025 and 34% above normal. 90 JCP&L Results of Operations — Second Quarter of 2026 Compared with Second Quarter of 2025 Net income increased $17 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to lower other operating expenses, higher transmission revenues from regulated capital investments that increased rate base, true-up adjustments from the annual forward-looking transmission rate filing and increased customer demand. Revenues The $67 million increase in total revenues resulted from the following sources: For the Three Months Ended June 30, Revenues by Type of Service 2026 2025 Increase / (Decrease) (In millions) Distribution services $ 217 $ 225 $ (8) Generation sales 347 299 48 Transmission 91 63 28 Other 4 5 (1) Total Revenues $ 659 $ 592 $ 67 Distribution services revenue decreased $8 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to lower rider revenues and return of certain ZEC refunds in New Jersey as further described above. These refunds were offset by the amortization of a regulatory liability resulting in no impact to earnings. The decrease in revenue was partially offset by increased customer usage and demand as a result of the weather temperatures. Generation sales revenues increased $48 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to higher non-shopping generation auction rates. Transmission revenues increased $28 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to true-up adjustments from the annual forward-looking transmission rate filing, higher recovery of transmission operating expenses, and higher rate base from regulated investment programs. Operating Expenses Total operating expenses increased $37 million primarily due to: •Purchased power costs, which have no material impact to earnings, increased $46 million during the second quarter of 2026, as compared to the same period of 2025, primarily due to higher unit costs, partially offset by lower volumes. •Other operating expenses increased $57 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to: •Higher storm restoration expenses of $46 million, which were mostly deferred for future recovery; •Higher energy efficiency and other state mandated program costs of $10 million, which were deferred for future recovery, resulting in no material impact to earnings; and •Higher formula rate transmission operating and maintenance expenses of $8 million, which have no material impact to earnings. The increase was partially offset by: •Lower other operating expenses of $7 million, primarily due to the absence in 2026 of a legal reserve recognized in the second quarter of 2026, partially offset by planned maintenance expenses. •Depreciation expense decreased $2 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to the accelerated amortization of legacy smart meters in New Jersey, which concluded in December 2025, partially offset by a higher asset base. •Deferral of regulatory assets, net increased $64 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to a $48 million increase from higher deferral of storm restoration costs, a $14 million increase 91 due to generation and transmission related deferrals and a $5 million increase related to the amortization of a regulatory liability associated with ZEC refunds, as further described above, partially offset by a $3 million net decrease in other deferrals. Other Expenses Total other expenses increased $7 million in the second quarter of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issued since the second quarter of 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits. Income Taxes The effective tax rate for the three months ended June 30, 2026, and 2025, was 24.8% and 24.4%, respectively. 92 JCP&L Summary of Results of Operations — First Six Months of 2026 Compared with First Six Months of 2025 JCP&L’s financial results for the six months ended June 30, 2026, and 2025, were as follows: For the Six Months Ended June 30, (In millions) 2026 2025 (1) Change Revenues $ 1,325 $ 1,158 $ 167 Operating Expenses: Purchased power 727 601 126 Other operating expenses 418 282 136 Provision for depreciation 124 130 (6) Deferral of regulatory assets, net (182) (32) (150) General taxes 13 12 1 Total operating expenses 1,100 993 107 Other Income (Expense): Miscellaneous income, net 28 23 5 Interest expense - other (80) (59) (21) Interest expense - affiliates (5) (3) (2) Capitalized financing costs 25 19 6 Total other expense (32) (20) (12) Income taxes 48 36 12 Net Income $ 145 $ 109 $ 36 (1) Previously issued 2025 JCP&L amounts have been revised due to the correction of immaterial errors as discussed in Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants. Distribution services by customer class are summarized in the following table: For the Six Months Ended June 30, (In thousands) Actual Weather-Adjusted Electric Distribution MWh Deliveries 2026 2025 Increase (Decrease) 2026 2025 (Decrease) Residential 4,662 4,523 3.1 % 4,372 4,419 (1.1) % Commercial(1) 4,126 4,066 1.5 % 4,059 4,058 — % Industrial 857 862 (0.6) % 857 862 (0.6) % Total Electric Distribution MWh Deliveries 9,645 9,451 2.1 % 9,288 9,339 (0.5) % (1) Includes street lighting. Distribution deliveries for the residential and commercial classes were impacted by higher customer usage and demand as a result of the weather temperatures. Cooling degree days in the first six months of 2026 were 22% above the same period of 2025 and 35% above normal. Heating degree days in the second quarter of 2026 were 10% above the same period of 2025 and 5% above normal. 93 JCP&L Results of Operations — First Six Months of 2026 Compared with First Six Months of 2025 Net income increased $36 million in the first six months of 2026, as compared to the same period of 2025, primarily due to the absence in 2026 of severance and related costs that were recognized in the first quarter of 2025, true-up adjustments from the annual forward-looking transmission rate filing, lower other operating expenses, higher transmission revenues from regulated capital investments that increased rate base and increased customer demand. Revenues The $167 million increase in total revenues resulted from the following sources: For the Six Months Ended June 30, Revenues by Type of Service 2026 2025 Increase / (Decrease) (In millions) Distribution services $ 448 $ 448 $ — Generation sales: Retail 705 576 129 Wholesale 2 1 1 Total generation sales 707 577 130 Transmission 162 124 38 Other 8 9 (1) Total Revenues $ 1,325 $ 1,158 $ 167 Distribution services revenue was flat during the first six months of 2026, as compared to the same period of 2025, primarily due to weather temperatures that increased customer usage and demand, and higher rider revenues associated with certain regulated investment programs, offset by return of certain ZEC refunds in New Jersey as further described above. These refunds were offset by the amortization of a regulatory liability resulting in no impact to earnings. Generation sales revenues increased $130 million during the first six months of 2026, as compared to the same period of 2025, primarily due to higher non-shopping generation auction rates and higher sales volumes. Transmission revenues increased $38 million during the first six months of 2026, as compared to the same period of 2025, primarily due to higher recovery of transmission operating expenses, true-up adjustments from the annual forward-looking transmission rate filing, and higher rate base from regulated investment programs. Operating Expenses Total operating expenses increased $107 million primarily due to: •Purchased power costs, which have no material impact to earnings, increased $126 million during the first six months of 2026, as compared to the same period of 2025, primarily due to higher unit costs. •Other operating expenses increased $136 million in the first six months of 2026, as compared to the same period of 2025, primarily due to: •Higher storm restoration expenses of $127 million, of which $122 million were deferred for future recovery; •Higher energy efficiency and other state mandated program costs of $20 million, which were deferred for future recovery, resulting in no material impact to earnings; and •Higher formula rate transmission operating and maintenance expenses of $11 million, which have no material impact to earnings. The increase was partially offset by: •The absence in 2026 of $5 million of severance and related costs associated with FirstEnergy’s organizational changes announced and recognized in the first quarter of 2025; and •Lower other operating expenses of $17 million, primarily due to planned maintenance expenses and the absence in 2026 of a legal reserve recognized in the second quarter of 2025. 94 •Depreciation expense decreased $6 million in the first six months of 2026, as compared to the same period of 2025, primarily due to the accelerated amortization of legacy smart meters in New Jersey, which concluded in December 2025, partially offset by a higher asset base. •Deferral of regulatory assets, net increased $150 million in the first six months of 2026, as compared to the same period of 2025, primarily due to a $122 million increase from higher deferral of storm restoration costs, a $32 million increase from higher general and transmission deferrals and a $5 million increase related to the amortization of a regulatory liability associated with ZEC refunds, as further described above, partially offset by $9 million related to net decreases in other deferrals. Other Expenses Total other expenses increased $12 million in the first six months of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issued since the second quarter of 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits. Income Taxes The effective tax rate for the six months ended June 30, 2026, and 2025, was 24.9% and 24.8%, respectively. 95