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Utility Rate Regulation | 12 Months Ended
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Dec. 31, 2025
Utility Rate Regulation [Line Items] |
Utility Rate Regulation | 7. Utility Rate Regulation Regulatory Assets and Liabilities (All Registrants) PPL, PPL Electric, LG&E and KU reflect the effects of regulatory actions in the financial statements for their rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to an item will be recovered or refunded within a year of the balance sheet date. (PPL) RIE is subject to the jurisdiction of the RIPUC, the Rhode Island Division of Public Utilities and Carriers, and the FERC. RIE operates under a FERC-approved open access transmission tariff. RIE's base distribution rates are calculated based on recovery of costs as well as a return on rate base. Certain other recovery mechanisms exist to recover expenses and capital investments with a return on rate base separate from the base distribution rate case process. (PPL, LG&E and KU) LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the VSCC and the FERC. Prior to January 1, 2026, LG&E's and KU's Kentucky base rates were calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. Effective January 1, 2026, pursuant to the KPSC rate case, Kentucky base rates are calculated based on a return on rate base (net utility plant plus certain regulatory assets and working capital less accumulated deferred income taxes and certain regulatory liabilities) and include recovery of applicable operations and maintenance expenses. (PPL and KU) KU's Virginia base rates are calculated based on recovery of costs as well as a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except for regulatory assets and liabilities related to the levelized fuel factor, accumulated deferred income taxes, pension and postretirement benefits, and AROs related to certain CCR impoundments, are excluded from the return on rate base utilized in the calculation of Virginia base rates, no return is earned on the related assets. KU's rates to municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets. (PPL and PPL Electric) PPL Electric is subject to the jurisdiction of the PAPUC and the FERC. PPL Electric's distribution base rates are calculated based on recovery of costs as well as a return on distribution rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions) and an annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets. (All Registrants) The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations at December 31:
| PPL |  | PPL Electric |  | LG&E |  | KU
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
Current Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas supply clause | $ | 10 |  |  | $ | 3 |  |  | $ | — |  |  | $ | — |  |  | $ | 10 |  |  | $ | 3 |  |  | $ | — |  |  | $ | — |
Rate adjustment mechanisms | 86 |  |  | 95 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Renewable energy certificates | 21 |  |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm damage expense rider | 53 |  |  | 68 |  |  | 53 |  |  | 68 |  |  | — |  |  | — |  |  | — |  |  | — |
Transmission service charge | 61 |  |  | 44 |  |  | — |  |  | 27 |  |  | — |  |  | — |  |  | — |  |  | — |
ISR deferral | 6 |  |  | 22 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
TCJA | 40 |  |  | 21 |  |  | 40 |  |  | 21 |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 31 |  |  | 53 |  |  | 19 |  |  | 17 |  |  | 9 |  |  | 5 |  |  | 1 |  |  | 1 |
Total current regulatory assets | $ | 308 |  |  | $ | 320 |  |  | $ | 112 |  |  | $ | 133 |  |  | $ | 19 |  |  | $ | 8 |  |  | $ | 1 |  |  | $ | 1 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Defined benefit plans | $ | 961 |  |  | $ | 967 |  |  | $ | 477 |  |  | $ | 473 |  |  | $ | 212 |  |  | $ | 226 |  |  | $ | 144 |  |  | $ | 149 |
Plant outage costs | 23 |  |  | 30 |  |  | — |  |  | — |  |  | 5 |  |  | 7 |  |  | 18 |  |  | 23 |
Net metering | 164 |  |  | 147 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Environmental cost recovery | 102 |  |  | 96 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm costs | 113 |  |  | 113 |  |  | 42 |  |  | 22 |  |  | 24 |  |  | 20 |  |  | 38 |  |  | 29 |
Unamortized loss on debt | 18 |  |  | 20 |  |  | 2 |  |  | 3 |  |  | 8 |  |  | 9 |  |  | 6 |  |  | 6 |
Terminated interest rate swaps | 47 |  |  | 53 |  |  | — |  |  | — |  |  | 28 |  |  | 31 |  |  | 19 |  |  | 22 |
Accumulated cost of removal of utility plant | 184 |  |  | 173 |  |  | 184 |  |  | 173 |  |  | — |  |  | — |  |  | — |  |  | — |
AROs | 263 |  |  | 280 |  |  | — |  |  | — |  |  | 73 |  |  | 75 |  |  | 190 |  |  | 205 |
RAR | 76 |  |  | 83 |  |  | — |  |  | — |  |  | 76 |  |  | 83 |  |  | — |  |  | — |
Gas line inspections | 24 |  |  | 24 |  |  | — |  |  | — |  |  | 22 |  |  | 22 |  |  | 2 |  |  | 2 |
Advanced metering infrastructure | 67 |  |  | 28 |  |  | — |  |  | — |  |  | 28 |  |  | 14 |  |  | 39 |  |  | 14 |
IT system costs | 18 |  |  | — |  |  | 18 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 32 |  |  | 46 |  |  | 2 |  |  | 2 |  |  | 6 |  |  | 4 |  |  | 11 |  |  | 8 |
Total noncurrent regulatory assets | $ | 2,092 |  |  | $ | 2,060 |  |  | $ | 725 |  |  | $ | 673 |  |  | $ | 482 |  |  | $ | 491 |  |  | $ | 467 |  |  | $ | 458 |
| PPL |  | PPL Electric |  | LG&E |  | KU
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
Current Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Generation supply charge | $ | 45 |  |  | $ | 52 |  |  | $ | 45 |  |  | $ | 52 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Transmission service charge | 17 |  |  | — |  |  | 17 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Universal service rider | 17 |  |  | 3 |  |  | 17 |  |  | 3 |  |  | — |  |  | — |  |  | — |  |  | — |
Transmission formula rate | 62 |  |  | 1 |  |  | 23 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Rate adjustment mechanisms | 124 |  |  | 71 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency | 26 |  |  | 25 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
DSM | 21 |  |  | 17 |  |  | — |  |  | — |  |  | 8 |  |  | 7 |  |  | 13 |  |  | 10 |
Environmental cost recovery | 6 |  |  | 12 |  |  | — |  |  | — |  |  | 3 |  |  | 6 |  |  | 3 |  |  | 6 |
Revenue decoupling mechanism | 55 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 3 |  |  | 32 |  |  | 1 |  |  | 2 |  |  | 2 |  |  | 1 |  |  | — |  |  | 6 |
Total current regulatory liabilities | $ | 376 |  |  | $ | 223 |  |  | $ | 103 |  |  | $ | 57 |  |  | $ | 13 |  |  | $ | 14 |  |  | $ | 16 |  |  | $ | 22 |
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 1,043 |  |  | $ | 1,022 |  |  | $ | — |  |  | $ | — |  |  | $ | 334 |  |  | $ | 314 |  |  | $ | 415 |  |  | $ | 408 |
Net deferred taxes | 1,798 |  |  | 1,899 |  |  | 708 |  |  | 739 |  |  | 415 |  |  | 439 |  |  | 467 |  |  | 498 |
Defined benefit plans | 342 |  |  | 294 |  |  | 120 |  |  | 100 |  |  | 23 |  |  | 24 |  |  | 69 |  |  | 65 |
Terminated interest rate swaps | 52 |  |  | 54 |  |  | — |  |  | — |  |  | 26 |  |  | 27 |  |  | 26 |  |  | 27 |
Advanced metering infrastructure | 30 |  |  | 13 |  |  | — |  |  | — |  |  | 10 |  |  | 4 |  |  | 20 |  |  | 9 |
Other | 53 |  |  | 53 |  |  | — |  |  | — |  |  | 1 |  |  | 7 |  |  | — |  |  | 2 |
Total noncurrent regulatory liabilities | $ | 3,318 |  |  | $ | 3,335 |  |  | $ | 828 |  |  | $ | 839 |  |  | $ | 809 |  |  | $ | 815 |  |  | $ | 997 |  |  | $ | 1,009 |
Following is an overview of selected regulatory assets and liabilities presented in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters." Defined Benefit Plans (All Registrants) Defined benefit plan regulatory assets and liabilities represent prior service cost and net actuarial gains and losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices and, generally, are amortized over the average remaining service lives of plan participants. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is remeasured. (PPL, LG&E and KU) As a result of previous rate case settlements and orders, the difference between pension cost calculated in accordance with LG&E's and KU's pension accounting policy and pension cost calculated using a 15-year amortization period for actuarial gains and losses and settlements are recorded as a regulatory asset. As of December 31, 2025, the balances were $72 million for PPL, $41 million for LG&E and $31 million for KU. As of December 31, 2024, the balances were $79 million for PPL, $44 million for LG&E and $35 million for KU. (PPL) RIE is subject to a pension rate adjustment mechanism whereby the difference in amounts allowed to be recovered in base rates and the actual costs of RIE's pension and other postretirement benefit plans that are to be recovered from or passed back to customers in future periods, are also recorded as regulatory assets and liabilities. (All Registrants) Storm Costs PPL Electric, LG&E and KU have the ability to establish or request regulatory assets for expenses related to specific extraordinary storms from the PAPUC, the KPSC and the VSCC, for regulatory accounting and reporting purposes. Once such authority is granted, LG&E and KU can request recovery of those expenses in a base rate case and begin amortizing the costs when recovery starts. PPL Electric can recover qualifying expenses caused by major storm events, as defined in its retail tariff, over three years through the Storm Damage Expense Rider commencing in the application year after the storm occurred. LG&E's and KU's regulatory assets for storm costs approved for base rate recovery are being amortized through various dates ending in 2031. As provided in the Amended Settlement Agreement (ASA), RIE has the authority from the RIPUC to treat certain incremental O&M expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once all expenses for the extraordinary storm have been finalized, RIE files a final accounting of those storm expenses with the RIPUC that is subject to review by the RIPUC and the Rhode Island Division of Public Utilities and Carriers. Unamortized Loss on Debt Unamortized loss on debt represents losses on long-term debt refinanced, reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2053 for PPL Electric, through 2042 for KU, and through 2044 for LG&E. Accumulated Cost of Removal of Utility Plant RIE, LG&E and KU charge costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period. Net Deferred Taxes Regulatory liabilities associated with net deferred taxes represent the future revenue impact from the adjustment of deferred income taxes required primarily for excess deferred taxes and unamortized investment tax credits, largely a result of the TCJA. (PPL and PPL Electric) Generation Supply Charge (GSC) The GSC is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service. The recovery includes charges for generation supply, as well as administration of the acquisition process. In addition, the GSC contains a reconciliation mechanism whereby any over- or under-recovery from prior periods is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent rate filing period. Transmission Service Charge (TSC) PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PAPUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year. RIE arranges transmission service on behalf of its customers and bills the costs of those services to customers, pursuant to its Transmission Service Cost Adjustment Provision. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year. Transmission Formula Rate PPL Electric's transmission revenues are billed in accordance with a FERC-approved Open Access Transmission Tariff that utilizes a formula-based rate recovery mechanism. Under this formula, rates are put into effect on January 1st of each year based upon actual expenditures from the most recently filed FERC Form 1, forecasted capital additions, and other data based on PPL Electric's books and records. Rates are compared during the year to the estimated annual expenses and capital additions that will be filed in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts. Under the mechanism, any difference between the revenue requirement in effect and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability, and the regulatory asset or regulatory liability is to be recovered from or returned to customers starting one year after the conclusion of the rate year. Storm Damage Expense Rider (SDER) The SDER is a reconcilable automatic adjustment clause under which PPL Electric annually will compare actual storm costs to storm costs allowed in base rates and refund or recover any differences from customers. In the 2015 rate case settlement approved by the PAPUC in November 2015, it was determined that reportable storm damage expenses to be recovered annually through base rates will be set at $20 million. The SDER will recover from or refund to customers the applicable expenses from reportable storms as compared to the $20 million recovered annually through base rates. Universal Service Rider (USR) The USR provides for recovery of costs associated with universal service programs, OnTrack and Winter Relief Assistance Program (WRAP), provided by PPL Electric to residential customers. OnTrack is a special payment program for low-income households and WRAP provides low-income customers a means to reduce electric bills through energy saving methods. The USR rate is applied to residential customers who receive distribution service. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year. TCJA As a result of the reduced U.S federal corporate income tax rate as enacted by the TCJA, the PAPUC ruled that these tax benefits should be refunded to customers. Timing differences between the recognition of these tax benefits and the refund of the benefit to the customer creates a regulatory liability. PPL Electric's liability is being credited back to distribution customers through a temporary negative surcharge and remains in place until PPL Electric files and the PAPUC approves new base rates. The TCJA is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year. IT System Costs IT system costs represent expenditures incurred associated with implementing strategic information technology investments. As part of the ongoing rate case proceedings, PPL Electric has requested certain of these implementation costs to be treated as capital for ratemaking purposes to be recovered over the useful life of the associated IT asset. Recovery of these costs is subject to approval by the PAPUC, but PPL and PPL Electric believe recovery of these costs is probable. (PPL, LG&E and KU) AROs As discussed in Note 1, for LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal. Terminated Interest Rate Swaps Net realized gains and losses on all interest rate swaps are recovered through regulated rates. As such, any gains and losses on these derivatives are included in regulatory assets or liabilities and are primarily recognized in "Interest Expense" on the Statements of Income over the life of the associated debt. Plant Outage Costs From July 1, 2017 through June 30, 2021, plant outage costs were normalized for ratemaking purposes based on an average level of expenses. Plant outage expenses that were greater or less than the average would be collected from or returned to customers, through future base rates. Effective July 1, 2021, under-recovered plant outage costs are being amortized through 2029 for LG&E and KU. Advanced Metering Infrastructure (AMI) In 2021 base rate case orders from the KPSC, LG&E and KU received approval to record regulatory assets comprised of the operating expenses associated with implementation of the AMI project, the incremental difference between AFUDC accrued at LG&E's and KU's weighted average cost of capital and that calculated using the methodology approved by the FERC, and the remaining net book value of the retired legacy meters replaced by AMI. Additionally, LG&E and KU received approval to record regulatory liabilities comprised of meter reading and field service expense savings since their previous rate case and the cost of capital impact for legacy meters replaced and retired during the AMI implementation. Recovery and/or return of these costs was approved effective January 1, 2026 in the base rate case proceedings. (PPL) Energy Efficiency The energy efficiency mechanism is designed to collect the estimated costs of RIE's energy efficiency plan for the upcoming calendar year. Any differences between revenue billed to customers through RIE's energy efficiency charge and the costs of RIE's energy efficiency programs, as approved by the RIPUC, are recorded as regulatory assets or regulatory liabilities. The final annual over or under collection is reconciled in the next year's energy efficiency plan filing, as part of the reconciliation factor calculation. RIE may file to change the energy efficiency plan charge at any time should significant over-or under-recoveries occur. Net Metering The net metering mechanism provides for recovery of costs associated with customer-installed on-site generation facilities, including the costs of renewable generation credits. Net metering is reconcilable annually, and any over- or under-recovery from customers will be refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year. Rate Adjustment Mechanisms In addition to commodity costs, RIE is subject to a number of additional rate adjustment mechanisms whereby a regulatory asset or regulatory liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the RIPUC. The rate adjustment mechanisms are reconcilable, and any over- or under-recovery from customers are to be refunded or recovered annually in the subsequent year. Renewable Energy Certificates The Renewable Energy Certificates regulatory asset represents deferred costs associated with RIE's compliance obligation with the Rhode Island Renewable Portfolio Standard (RPS). The RPS is legislation established to foster the development of new renewable energy sources. The regulatory asset will be recovered over the next year. Environmental Cost Recovery (PPL, LG&E and KU) Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Clean Air Act and those federal, state or local environmental requirements, which apply to coal combustion wastes and by-products from coal-fired electricity generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the opportunity to roll-in ECR amounts to base rates each two-year period. The KPSC has authorized a return on equity of 9.35% for existing approved ECR projects. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is typically recovered or refunded within 12 months. (PPL) RIE's rate plans provide for specific rate allowances for RIE's share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated, with variances deferred for future recovery from, or return to, customers. RIE believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. The regulatory asset represents the excess of amounts incurred for RIE's actual site investigation and remediation costs versus amounts received in rates. (PPL and LG&E) Gas Supply Clause LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs and customer usage from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause previously included a separate natural gas procurement incentive mechanism, which allowed LG&E's rates to be adjusted annually to share savings between the actual cost of gas purchases and market indices, with the shareholders and the customers during each performance-based rate year (12 months ending October 31). The operation of this incentive mechanism expired on October 31, 2024, but savings achieved through October 31, 2024 will be included in LG&E's rates through October 31, 2026. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are typically recovered or refunded within 18 months. RAR The RAR rider was established by KPSC orders in 2021 to provide recovery of and return on the retirement costs of certain electric generating units, including the remaining net book value of each unit, materials and supplies that cannot be used at other plants and any associated removal costs, upon their retirement over a ten-year period following retirement. Costs included as of December 31, 2025 represent the remaining retirement costs of Mill Creek Unit 1 to be recovered through April 2034. Regulatory Matters Rhode Island Activities (PPL) Rate Case Proceeding On November 26, 2025, RIE filed a request with the RIPUC for an increase in electric and natural gas base distribution rates, and approval of certain regulatory and accounting treatments. In its application, RIE seeks to implement a two-year rate plan. In the first year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect additional operating revenue of approximately $181 million ($66 million or 18.2% in electricity revenues and $115 million or 36.4% in gas revenues). In the second year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect the proposed base distribution rate increases for electric and gas in the first year of the rate plan and additional operating revenues of approximately $49 million ($17 million or 3.6% in electricity revenues and $32 million or 7.4% in gas revenues). The application is based on a historical test year of September 1, 2024 through August 31, 2025 and requested an authorized ROE of 10.75%. Subject to RIPUC approval, new rates are expected to become effective on September 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the RIPUC is anticipated during the third quarter of 2026. PPL cannot predict the outcome of the proceeding. Hold Harmless Implementation Agreement As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers required PPL to hold harmless Rhode Island customers from the impact of future rate increases resulting from changes in Accumulated Deferred Income Taxes as a result of the Acquisition (the Hold Harmless Commitment). On June 13, 2025, an agreement was entered into by and among RIE, PPL, PPL Rhode Island Holdings and the Rhode Island Division of Public Utilities and Carriers Advocacy Section (the Hold Harmless Implementation Agreement) to satisfy the Hold Harmless Commitment by providing approximately $155 million in miscellaneous bill credits issued to customers, with approximately $74 million to be issued in the first quarter of 2026 and approximately $81 million to be issued in the first quarter of 2027. The bill credits would be recorded as a reduction to revenue in the periods in which the credits are applied to customers' bills. On September 10, 2025, the Rhode Island Division of Public Utilities and Carriers issued an order confirming that RIE's provision of proposed miscellaneous bill credits as set forth in the Hold Harmless Implementation Agreement would satisfy the Hold Harmless Commitment. Also on September 10, 2025, the RIPUC opened a docket to evaluate the miscellaneous bill credit proposal set forth in the Hold Harmless Implementation Agreement, including the underlying rate accounting, and required RIE to file a tariff advice with the RIPUC, which RIE filed on October 2, 2025. After responding to discovery in that proceeding and before the evidentiary hearing was held or convened, RIE filed a notice of withdrawal of its tariff advice filing noting that it would hold in abeyance a comprehensive satisfaction of the Hold Harmless Commitment at this time. As a result of RIE's filing the notice of withdrawal, the Commission cancelled the evidentiary hearing. The docket remains open, but there has been no further activity since RIE's withdrawal of the tariff advice and the RIPUC's cancellation of the evidentiary hearing. PPL cannot predict whether there will be any further proceedings on the docket or the outcome of any further proceedings that may occur. Winter Bill Volatility Docket At an Open Meeting on November 24, 2025, the RIPUC approved several measures to help mitigate winter bill increases for electric customers. First, the RIPUC approved miscellaneous bill credits for all residential electric customers of $23.54 per month for January, February, and March 2026. Second, the RIPUC paused the Storm Fund Replenishment Factor for usage on and after January 1, 2026, subject to further review through the 2026 Annual Retail Rate Filing. Third, the RIPUC paused the electric Energy Efficiency Charge for usage beginning January 1, 2026 through March 31, 2026. To offset the costs of the miscellaneous bill credits, the RIPUC directed RIE to apply the December 31, 2025 electric Energy Efficiency fund balance, net of any earned incentives, and directed RIE to transfer $11 million from the storm fund balance. The RIPUC approved future cost recovery for RIE of any unfunded balance of the miscellaneous bill credits through future identified offsets and/or a reconciling recovery mechanism to be determined in conjunction with the 2026 electric retail rate filing to allow recovery by December 31, 2026. Any remaining unfunded balance shall accrue at RIE's weighted average cost of capital. FY 2026 Gas ISR Plan On March 28, 2025, the RIPUC approved the FY 2026 Gas ISR Plan of $165 million, of which $147 million is for capital investment spend and $18 million is spend for paving costs as operation and maintenance (O&M), plus a potential additional $15 million is available if certain regulations are implemented by the PHMSA. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025. FY 2027 Gas ISR Plan On December 22, 2025, RIE filed its FY 2027 Gas ISR Plan with the RIPUC with a budget of $184 million that primarily included $166 million of capital investment spend and $17 million for spending on curb-to-curb paving. A decision from the RIPUC on the Plan is expected by March 31, 2026. RIE cannot predict the outcome of this matter. FY 2026 Electric ISR Plan On March 28, 2025, the RIPUC approved a FY 2026 Electric ISR Plan of $219 million for capital investment spend (including $88 million for Advanced Metering Functionality), $14 million for vegetation operations and maintenance spend and $1 million for Other O&M spend. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025. FY 2027 Electric ISR Plan On December 22, 2025, RIE filed its FY 2027 Electric ISR Plan with the RIPUC with a budget that primarily included $154 million of capital investment spend (including $18 million for Advanced Metering Functionality) and $13 million of vegetation operation and maintenance spend. A decision from the RIPUC is expected by March 31, 2026. RIE cannot predict the outcome of this matter. Kentucky Activities (PPL, LG&E and KU) Rate Case Proceedings On May 30, 2025, LG&E and KU filed requests with the KPSC for an increase in annual electricity and gas revenues of approximately $391 million ($105 million and $226 million in electricity revenues at LG&E and KU and $60 million in gas revenues at LG&E) and approval of certain regulatory and accounting treatments. The revenue increases would be an increase of 8.3% and 11.5% in electricity revenues at LG&E and KU, and an increase of 14.0% in gas revenues at LG&E. The applications were based on a forecasted test year of January 1, 2026 through December 31, 2026 and requested an authorized ROE of 10.95%. New interim rates became effective on January 1, 2026, subject to refund pursuant to the KPSC's final order. Certain counterparties have intervened in the proceedings. On October 20, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation (the agreement) regarding a proposed resolution of issues with a majority of the intervenors in the proceedings. Under the agreement, the parties proposed that the KPSC should issue orders granting a revised increase in annual electricity and gas revenues of approximately $235 million ($58 million and $132 million in electricity revenues at LG&E and KU and $45 million in gas revenues at LG&E.) The agreement proposed a revised authorized ROE of 9.90%. The agreement proposed a "stay out" commitment from LG&E and KU to refrain from effective base rate increases before August 1, 2028, subject to certain exceptions. In connection with the stay out period, the agreement also proposed the establishment of two new rate adjustment clause mechanisms, a Generation Cost Recovery Adjustment Clause (GCR) and a Sharing Mechanism Adjustment Clause (SM). The proposed GCR mechanism would provide LG&E and KU recovery of and return on investment of covered costs (excluding fuel amounts, which LG&E and KU can recover via an existing rate mechanism) of relevant new generation and energy storage assets authorized in the 2022 and 2025 CPCN proceedings (excluding the Mill Creek Unit 6 NGCC, see "2025 CPCN" for more information regarding the Mill Creek Unit 6 NGCC) as they are placed in service. The proposed SM mechanism would address any base rate revenue deficiency or surplus during the final thirteen months of the stay out period, July 2027 through July 2028, below or above a suggested ROE band of 9.40% to 10.15%. Any such base rate revenue deficiency or surplus would be collected from or returned to customers over a thirteen-month billing period beginning November 2028. Following issuance of the 2025 CPCN Order, LG&E and KU filed supplemental testimony with the KPSC in the rate case proceedings seeking recovery of the Mill Creek Unit 2 stay open costs through a proposed additional rate adjustment clause mechanism. The agreement further proposed that LG&E and KU use regulatory deferral accounting for actual expenses above or below base rate levels for certain expenses including: pension and post-retirement benefits, storm restoration, vegetation management, transmission waivers and credits, and gas line or well activities, with recovery of such deferred asset or liability amounts to be addressed in future rate cases. On February 16, 2026, the KPSC issued orders approving portions of the October 2025 stipulation and recommendation, with modifications. The KPSC orders provide for increases in annual electricity and gas revenues of $233 million ($59 million and $128 million in electricity revenues at LG&E and KU and $46 million in gas revenues at LG&E.) The orders include authorized returns on equity of 9.775% for base rate purposes and 9.675% for capital rate adjustment mechanisms. The KPSC orders approve LG&E's and KU's requests for establishment of certain new rate adjustment mechanisms or tariffs, with modifications: • a temporary Pilot Generation Recovery Adjustment Clause (PGR) to provide recovery of and return on investment of applicable costs of certain new generation and storage assets being built or anticipated to be built by LG&E and KU as authorized in the 2022 CPCN proceeding; • the inclusion in the PGR of recovery of and return on investment of certain costs associated with a potential extension of the operating life of LG&E's Mill Creek Unit 2 beyond its original 2027 retirement date; and • an Extremely High Load Factor Tariff for future applicable customers, such as data centers, which includes requirements such as long-term contracts, minimum revenue payments and collateral security structures that help protect the interests of LG&E, KU and of other ratepayers. The PGR mechanism is similar to the GCR proposed in the stipulation, but restructured by the KPSC to be a pilot adjustment mechanism with a term until the earlier of ten months following the submission of LG&E's and KU's next base rate proceeding or the effective date of new rates in such proceeding, with the expectation that the mechanism would be reviewed in such proceeding. The pilot mechanism will apply to the planned Mill Creek Unit 5, Brown Battery Energy Storage System, Mercer County Solar and Marion County Solar generation-related projects. The KPSC also included Mill Creek Unit 2's potential stay-open costs in the PGR in lieu of approving the stipulation's request for a stand-alone adjustment mechanism for such costs. Finally, the KPSC excluded from coverage under the PGR costs related to Mill Creek Unit 6 and Brown Unit 12 planned new generation assets due to their anticipated in-service dates falling outside of the estimated pilot mechanism's duration, but without prejudice to LG&E and KU seeking recovery of such costs in future proceedings. The KPSC orders also approved, approved with modifications, or denied in some cases, other requested accounting and rate matters relating to regulatory assets or liabilities, depreciation rates, and other areas. The rate changes have a retroactive effective date as of January 1, 2026. Consistent with authorized rate case procedures, LG&E and KU will refund to customers amounts billed in excess of the final approved rates within sixty days. The KPSC orders did not approve the SM adjustment clause that had been requested in the stipulation and made no modifications to the stay out offer by LG&E and KU to refrain from effective base rate increases prior to August 2028. LG&E and KU and all intervenors have rights to request rehearing or appeal of the orders of the KPSC and because the KPSC orders modified or denied terms of the proposed stipulation, LG&E and KU and all stipulating parties have the right to withdraw from the stipulation. LG&E and KU continue to evaluate the details contained in the orders and related matters as they consider next steps. PPL, LG&E and KU cannot predict the outcome of this matter. 2025 CPCN On February 28, 2025, LG&E and KU filed an application with the KPSC regarding certain future plans for new generation and generation-related construction matters. The proposals included in the application were intended to serve anticipated load growth, including from potential data center demand in LG&E's or KU's service territory. The proposals did not include retirements of coal or other fossil-fueled plants, which would require additional KPSC approval procedures under Kentucky legislation enacted in 2023 and 2024. LG&E and KU submitted a joint application to the KPSC for approval of certain certificates of public convenience and necessity, site compatibility certificates, and accounting treatment, where applicable, relating to a number of generation-related plans or projects that generally are expected to become operational or established within the next six years. The aggregate projected capital expenditures associated with these proposals were expected to be $3.7 billion. The application included proposals to build: •a 645 MW NGCC generation unit at KU's E.W. Brown station (Brown Unit 12), •a 645 MW NGCC generation unit at LG&E's Mill Creek station (Mill Creek Unit 6), •a four-hour 400 MW (1600 MWh total) battery energy storage system (BESS) at LG&E's Cane Run station, and •a selective catalytic reduction (SCR) environmental facility at KU's Ghent station Unit 2 (Ghent Unit 2). The new NGCC units are anticipated to be wholly owned by LG&E and the BESS unit jointly owned by LG&E (32%) and KU (68%), with actual project costs allocated consistent with LG&E's and KU's ultimate ownership shares and existing shared dispatch, cost allocation, tariff or other frameworks. The proposed Mill Creek Unit 6 NGCC is in addition to a new NGCC unit currently under construction at that location (Mill Creek Unit 5). The filing also noted projected in service dates for the projects, including the Brown Unit 12 NGCC in 2030, the Mill Creek Unit 6 NGCC in 2031, the Cane Run BESS in 2028 and the Ghent Unit 2 SCR in 2028. On July 29, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation regarding a proposed resolution of issues with several of the intervenors in the CPCN proceeding (stipulation). The stipulation recommended to the KPSC the approval of the large majority of LG&E's and KU's requested generation-related projects and associated accounting matters, subject to certain changes. Under the stipulation, the parties agreed the KPSC should issue an order granting a CPCN for the proposed: (a) Brown Unit 12 NGCC; (b) Mill Creek Unit 6 NGCC; and (c) Ghent Unit 2 SCR. In addition, the proposal to build the $775 million Cane Run BESS would be withdrawn without prejudice, the relevant costs regarding the proposed $1.4 billion Mill Creek Unit 6 NGCC would be recovered through a new rate adjustment clause mechanism, the retirement date for the existing Mill Creek Unit 2 coal unit would be extended from 2027 to the operational date of the proposed Mill Creek Unit 6 NGCC or afterwards, subject to relevant future economic analysis, regulatory or environmental authorizations, and the relevant costs to continue to operate the Mill Creek Unit 2 coal unit would be recovered through a new rate adjustment clause mechanism. The stipulation also contained provisions relating to regulatory asset accounting, proposed data center tariffs, future renewable power requests-for-proposals and other matters. LG&E and KU would retain the right to seek approval of the potentially withdrawn Cane Run BESS or similar substitute project in future regulatory proceedings. On October 28, 2025, the KPSC issued an order approving much of LG&E's and KU's July 2025 stipulation, with certain modifications. The order granted the requested CPCNs and site-related permits to construct the proposed Brown Unit 12 NGCC, Mill Creek Unit 6 NGCC, and Ghent Unit 2 SCR. The order authorized inclusion of relevant costs of the Ghent Unit 2 SCR in KU's existing environmental cost recovery rate mechanism. The order established a separate monitoring case to receive and consider information during the construction of Mill Creek Unit 6 NGCC. The order approved requests regarding regulatory asset deferral accounting treatment for certain AFUDC related amounts and noted the KPSC's expectation that the stipulating parties would follow through with their commitments regarding tariffs and power supply contracts related to potential future data center or high load customers in LG&E's and KU's pending rate proceedings. The order also approved other elements of the stipulation or the originally-filed application, with minor modifications. The KPSC decided not to approve LG&E's and KU's proposed new rate adjustment cost recovery mechanisms for certain costs associated with Mill Creek Unit 6 NGCC and costs associated with operating the Mill Creek Unit 2 coal plant beyond its original retirement date in 2027. However, the denials were without prejudice to resubmission and the KPSC encouraged the parties to provide additional evidence on such matters in separate proceedings. LG&E and KU provided such evidence addressing recovery of the Mill Creek Unit 2 stay open costs in their pending rate case proceedings. Recovery of Mill Creek Unit 6 costs will be addressed in a future proceeding. The KPSC declined to rule on the matter related to the retirement date of Mill Creek Unit 2 coal plant. The KPSC indicated that a request for a new retirement approval proceeding may be required should LG&E elect to operate Mill Creek Unit 2 beyond its existing approved retirement date and seek to later retire the unit. In light of the conditional withdrawal in the stipulation, the order did not include a CPCN for the Cane Run BESS. LG&E and KU retain the right to seek approval of the Cane Run BESS project or similar substitute projects at any time in future regulatory proceedings. Kentucky January 2025 Storm In January 2025, LG&E and KU experienced snow, ice, sleet and freezing rain in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets. On January 31, 2025, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance (O&M) expenses portion of the costs incurred related to the storm. On March 19, 2025, the KPSC issued an order authorizing LG&E and KU to establish, for accounting purposes only, regulatory assets based on the jurisdictional incremental costs of extraordinary O&M expense incurred by LG&E and KU as a result of the 2025 winter storm, with recovery amounts and amortization thereof to be determined in subsequent base rate proceedings. LG&E and KU cannot predict the outcome of these matters. As of December 31, 2025, LG&E and KU had recorded regulatory assets related to the storm of $2 million and $7 million. Mill Creek Unit 1 and Unit 2 RAR Application (PPL and LG&E) In November 2023, the KPSC issued an order approving, among other items, the requested retirement of Mill Creek Units 1 and 2. On October 4, 2024, LG&E submitted an application related to the retirement of Mill Creek Unit 1, which occurred on December 31, 2024, requesting recovery of associated costs under the RAR. On February 24, 2025, the KPSC issued an order approving LG&E's cost recovery for Mill Creek Unit 1 under the RAR of $125 million and related amounts were included in bills beginning in May 2025. LG&E anticipates the recovery of associated costs, including the remaining net book value, for Mill Creek Unit 2 through the RAR. The remaining net book value of Mill Creek Unit 2 was approximately $199 million at December 31, 2025 and LG&E is continuing to depreciate using the current approved rates through its retirement date. LG&E expects to reclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period of ten years in accordance with the RAR. There can be no assurance that these costs will be recovered in the amounts or over the time periods that LG&E expects. See the "2025 CPCN" and "Rate Case Proceedings" discussions above for information regarding potential changes in the retirement date of Mill Creek Unit 2. Pennsylvania Activities (PPL and PPL Electric) Rate Case Proceeding On September 30, 2025, PPL Electric filed a request with the PAPUC for an increase in distribution base rates of approximately $356 million, more than $50 million of which is already included in customer bills through rate recovery mechanisms, and approval of certain regulatory and accounting treatments. The proposed increase in distribution base rates would increase PPL Electric's total annual revenue by approximately 8.6%. The application is based on a fully projected future test year of July 1, 2026 through June 30, 2027 and requested an authorized ROE of 11.3%. Subject to PAPUC approval, new rates are expected to become effective on July 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the PAPUC is anticipated during the second quarter of 2026. PPL and PPL Electric cannot predict the outcome of the proceeding. DSIC Petition On April 26, 2024, PPL Electric filed a Petition with the PAPUC requesting that the PAPUC waive PPL Electric's DSIC cap of 5% of billed revenues and increase the maximum allowable DSIC to 9% for bills rendered on or after January 1, 2025. On February 28, 2025, the PAPUC issued its written order permitting PPL Electric to increase its DSIC cap from 5% to 7.5% for bills rendered on or after March 13, 2025 until the effective date of rates established in PPL Electric's next base rate case or the end of the PPL Electric's 2023-2027 Long-term Infrastructure Improvement Plan, whichever occurs first, at which time it will return to 5%. Federal Matters FERC Transmission Rate Filing (PPL, LG&E and KU) In 2018, LG&E and KU applied to the FERC requesting elimination of certain on-going waivers and credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the U.S. Court of Appeals - D.C. Circuit (D.C. Circuit Court of Appeals) regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. In August 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. On May 18, 2023, the FERC issued an order on remand reversing its 2019 decision and requiring LG&E and KU to refund credits previously withheld, including under such transition mechanism. LG&E and KU filed a petition for review of the FERC's May 18, 2023 order with the D.C. Circuit Court of Appeals and provided refunds in accordance with the FERC order on December 1, 2023. The FERC issued an order on LG&E's and KU's compliance filing on November 16, 2023, and LG&E and KU filed a petition for review of this November 16, 2023 order on February 14, 2024. The FERC issued the substantive order on rehearing on March 21, 2024, reaffirming its prior decision. On August 8, 2025, the D.C. Circuit Court of Appeals issued a procedural ruling vacating the FERC's prior orders and remanded the matter back to the FERC for further proceedings. LG&E and KU cannot predict the ultimate outcome of the proceedings or any other post decision process but do not expect the annual impact to have a material effect on their operations or financial condition. LG&E and KU currently receive recovery of certain waivers and credits primarily through existing base rate levels. Recovery of Transmission Costs (PPL) NE-ISO allocates RIE's costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT). The ROE for transmission rates under the ISO-NE OATT is the subject of four complaints that are pending before the FERC. On October 16, 2014, the FERC issued an order on the first complaint, Opinion No. 531-A, resetting the base ROE applicable to transmission assets under the ISO-NE OATT from 11.14% to 10.57% effective as of October 16, 2014 and establishing a maximum ROE of 11.74%. On April 14, 2017, this order was vacated and remanded by the D.C. Circuit Court of Appeals (Court of Appeals). After the remand, the FERC issued an order on October 16, 2018 applicable to all four pending cases where it proposed a new base ROE methodology that, with subsequent input and support from the New England Transmission Owners (NETO), yielded a base ROE of 10.41%. Subsequent to the FERC's October 2018 order in the New England Transmission Owners cases, the FERC further refined its ROE methodology in another proceeding and has applied that refined methodology to transmission owners' ROEs in other jurisdictions, and the NETOs filed further information in the New England matters to distinguish their case. Those determinations in other jurisdictions have been vacated and remanded back to the FERC for further proceedings by the D.C. Circuit Court of Appeals. The proceeding and the final base rate ROE determination in the New England matters remain open, pending a final order from the FERC. PPL cannot predict the outcome of this matter, and an estimate of the impact cannot be determined. Other Purchase of Receivables Program (PPL and PPL Electric) In accordance with RIPUC-approved and PAPUC-approved purchase of accounts receivable programs, RIE and PPL Electric purchase certain accounts receivable from alternative electricity suppliers at a discount, which reflects a provision for uncollectible accounts. The alternative electricity suppliers have no continuing involvement or interest in the purchased accounts receivable. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. During 2025, 2024 and 2023, RIE purchased $314 million, $299 million and $235 million of accounts receivable from alternative suppliers. During 2025, 2024 and 2023, PPL Electric purchased $1.6 billion, $1.5 billion and $1.5 billion of accounts receivable from alternative suppliers.

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