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Utility Rate Regulation | 9 Months Ended
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Sep. 30, 2025
Regulated Operations [Abstract] |
Utility Rate Regulation | 6. Utility Rate Regulation (All Registrants) The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.
| PPL |  | PPL Electric |  | LG&E |  | KU
| September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024
Current Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rate adjustment mechanisms | $ | 100 |  |  | $ | 95 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Renewable energy certificates | 27 |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm damage expense rider | 35 |  |  | 68 |  |  | 35 |  |  | 68 |  |  | — |  |  | — |  |  | — |  |  | — |
Gas supply clause | 15 |  |  | 3 |  |  | — |  |  | — |  |  | 15 |  |  | 3 |  |  | — |  |  | — |
Transmission service charge | 63 |  |  | 44 |  |  | — |  |  | 27 |  |  | — |  |  | — |  |  | — |  |  | — |
DSIC | 9 |  |  | 8 |  |  | 9 |  |  | 8 |  |  | — |  |  | — |  |  | — |  |  | — |
TCJA customer refund and recovery | 38 |  |  | 21 |  |  | 38 |  |  | 21 |  |  | — |  |  | — |  |  | — |  |  | — |
ISR deferral | 7 |  |  | 22 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 18 |  |  | 45 |  |  | 8 |  |  | 9 |  |  | 9 |  |  | 5 |  |  | — |  |  | 1 |
Total current regulatory assets | $ | 312 |  |  | $ | 320 |  |  | $ | 90 |  |  | $ | 133 |  |  | $ | 24 |  |  | $ | 8 |  |  | $ | — |  |  | $ | 1 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Defined benefit plans | $ | 964 |  |  | $ | 967 |  |  | $ | 479 |  |  | $ | 473 |  |  | $ | 216 |  |  | $ | 226 |  |  | $ | 148 |  |  | $ | 149 |
Plant outage costs | 24 |  |  | 30 |  |  | — |  |  | — |  |  | 5 |  |  | 7 |  |  | 19 |  |  | 23 |
Net metering | 160 |  |  | 147 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Environmental cost recovery | 96 |  |  | 96 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm costs | 111 |  |  | 113 |  |  | 41 |  |  | 22 |  |  | 24 |  |  | 20 |  |  | 38 |  |  | 29 |
Unamortized loss on debt | 19 |  |  | 20 |  |  | 3 |  |  | 3 |  |  | 8 |  |  | 9 |  |  | 6 |  |  | 6 |
Terminated interest rate swaps | 48 |  |  | 53 |  |  | — |  |  | — |  |  | 28 |  |  | 31 |  |  | 20 |  |  | 22 |
Accumulated cost of removal of utility plant | 168 |  |  | 173 |  |  | 168 |  |  | 173 |  |  | — |  |  | — |  |  | — |  |  | — |
AROs | 272 |  |  | 280 |  |  | — |  |  | — |  |  | 76 |  |  | 75 |  |  | 196 |  |  | 205 |
RAR | 78 |  |  | 83 |  |  | — |  |  | — |  |  | 78 |  |  | 83 |  |  | — |  |  | — |
Gas line inspections | 24 |  |  | 24 |  |  | — |  |  | — |  |  | 22 |  |  | 22 |  |  | 2 |  |  | 2 |
Advanced metering infrastructure | 37 |  |  | 28 |  |  | — |  |  | — |  |  | 19 |  |  | 14 |  |  | 18 |  |  | 14 |
Other | 57 |  |  | 46 |  |  | 12 |  |  | 2 |  |  | 9 |  |  | 4 |  |  | 11 |  |  | 8 |
Total noncurrent regulatory assets | $ | 2,058 |  |  | $ | 2,060 |  |  | $ | 703 |  |  | $ | 673 |  |  | $ | 485 |  |  | $ | 491 |  |  | $ | 458 |  |  | $ | 458 |
| PPL |  | PPL Electric |  | LG&E |  | KU
| September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024
Current Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Generation supply charge | $ | 45 |  |  | $ | 52 |  |  | $ | 45 |  |  | $ | 52 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
ECR | 7 |  |  | 12 |  |  | — |  |  | — |  |  | 4 |  |  | 6 |  |  | 3 |  |  | 6 |
Transmission formula rate | 30 |  |  | 1 |  |  | 9 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Rate adjustment mechanisms | 71 |  |  | 71 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency | 25 |  |  | 25 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
DSM | 24 |  |  | 17 |  |  | — |  |  | — |  |  | 9 |  |  | 7 |  |  | 15 |  |  | 10 |
Revenue decoupling mechanism | 40 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 49 |  |  | 35 |  |  | 17 |  |  | 5 |  |  | 1 |  |  | 1 |  |  | 6 |  |  | 6 |
Total current regulatory liabilities | $ | 291 |  |  | $ | 223 |  |  | $ | 71 |  |  | $ | 57 |  |  | $ | 14 |  |  | $ | 14 |  |  | $ | 24 |  |  | $ | 22 |
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 1,037 |  |  | $ | 1,022 |  |  | $ | — |  |  | $ | — |  |  | $ | 328 |  |  | $ | 314 |  |  | $ | 411 |  |  | $ | 408 |
Net deferred taxes | 1,825 |  |  | 1,899 |  |  | 713 |  |  | 739 |  |  | 422 |  |  | 439 |  |  | 476 |  |  | 498 |
Defined benefit plans | 310 |  |  | 294 |  |  | 114 |  |  | 100 |  |  | 24 |  |  | 24 |  |  | 67 |  |  | 65 |
Terminated interest rate swaps | 52 |  |  | 54 |  |  | — |  |  | — |  |  | 26 |  |  | 27 |  |  | 26 |  |  | 27 |
Energy efficiency | 29 |  |  | 16 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 69 |  |  | 50 |  |  | — |  |  | — |  |  | 12 |  |  | 11 |  |  | 19 |  |  | 11 |
Total noncurrent regulatory liabilities | $ | 3,322 |  |  | $ | 3,335 |  |  | $ | 827 |  |  | $ | 839 |  |  | $ | 812 |  |  | $ | 815 |  |  | $ | 999 |  |  | $ | 1,009 |
Regulatory Matters Rhode Island Activities (PPL) FY 2026 Gas ISR Plan On December 31, 2024, RIE filed its FY 2026 Gas ISR Plan with the RIPUC with a budget that included $187 million of capital investment spend and up to $15 million of additional contingency plan spend in connection with the PHMSA's potential enactment of regulations during FY 2026 that, if enacted, would significantly alter RIE's leak detection and repair obligations under federal regulations. The plan also included proposed spending on curb-to-curb paving of $22 million. On March 28, 2025, the RIPUC approved a 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 operations and maintenance (O&M), plus a potential additional $15 million is available if the above-mentioned regulations are implemented by the PHMSA. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025. FY 2026 Electric ISR Plan On December 23, 2024, RIE filed its FY 2026 Electric ISR Plan with the RIPUC with a budget that included $248 million of capital investment spend (including $88 million for Advanced Metering Functionality (AMF)), $14 million of vegetation operation and maintenance (O&M) spend and $1 million of Other O&M spend. On March 28, 2025, the RIPUC approved a FY 2026 Electric ISR Plan of $219 million for capital investment spend (including $88 million for AMF), $14 million for vegetation management O&M 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. Hold Harmless Implementation Agreement As a condition to the Acquisition (as defined in Note 8 to the Financial Statements) of RIE in May 2022, PPL made a commitment to the Rhode Island Division of Public Utilities and Carriers 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 to satisfy RIE's obligations under the Hold Harmless Commitment of approximately $155 million, and proposes to resolve that amount through bill credits issued to customers, with approximately $74 million to be issued throughout the first quarter of 2026 and approximately $81 million to be issued throughout 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 approved the agreement. Also on September 10, 2025, the RIPUC opened a docket to evaluate RIE’s bill credit proposal, including the underlying rate accounting supporting the proposal, and required RIE to file a tariff advice with the RIPUC, which RIE filed on October 2, 2025. Discovery in this proceeding is ongoing and an evidentiary hearing is scheduled for November 18, 2025. PPL cannot predict the outcome of the RIPUC inquiry. 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 are based on a forecasted test year of January 1, 2026 through December 31, 2026 and request an authorized ROE of 10.95%. Subject to KPSC approval, new rates are expected to become effective on January 1, 2026. 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 propose that the KPSC should issue orders granting a revised aggregate increase in annual electricity and gas revenues of approximately $235 million, comprising increases of $58 million and $132 million in electricity revenues at LG&E and KU, respectively, and $45 million in gas revenues at LG&E. The agreement proposes a revised authorized ROE of 9.90%. The agreement proposes 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 proposes the establishment of two new rate tracker 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 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 in 2031, 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 authorizes LG&E and KU to 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. A KPSC hearing in the underlying proceedings commenced on November 3, 2025. The agreement, as well as matters raised by non-agreeing intervenors, are subject to KPSC review and action, including approval, denial or modification. LG&E and KU anticipate a ruling from the KPSC during the fourth quarter of 2025, although the KPSC has until March 31, 2026 to issue its final order. PPL, LG&E and KU cannot predict the outcome of these proceedings. 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 are 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 are currently expected to be $3.7 billion over the 2025 to 2031 period. The application includes 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 (1,600 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 notes 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 recommends 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 agree 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 tracker mechanism, and the retirement date for the existing Mill Creek Unit 2 coal plant 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. The stipulation also contains 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 are providing 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. 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. The KPSC's order is subject to certain rights to request rehearing or appeal by LG&E and KU and all intervenors. LG&E and KU continue to evaluate the order and related matters and cannot predict the outcome should they or other parties decide to appeal or request a rehearing of these matters. 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 September 30, 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 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. LG&E expects these costs to be approximately $125 million and proposed to begin application of the RAR with bills issued in May 2025. On February 24, 2025, the KPSC issued an order approving LG&E’s cost recovery for Mill Creek Unit 1 under the RAR 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 $203 million at September 30, 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" discussion above for information regarding potential changes in the retirement date of Mill Creek Unit 2. Pennsylvania Activities (PPL and PPL Electric) Rate Case Proceedings 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. 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. Additionally, LG&E’s and KU’s current Kentucky rate proceedings include requests regarding elements of regulatory liabilities or assets associated with potential future decreases or increases in the transmission waivers and credits that are the subject of these FERC proceedings. Recovery of Transmission Costs (PPL) Until December 2022, RIE's transmission facilities were operated in combination with the transmission facilities of National Grid USA's New England affiliates, Massachusetts Electric Company (MECO) and New England Power (NEP), a National Grid USA affiliate, as a single integrated system with NEP designated as the combined operator. As of January 1, 2023, RIE operates its own transmission facilities. NE-ISO allocates RIE's costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT). According to the FERC orders, RIE is compensated for its actual monthly transmission costs, with its authorized maximum ROE of 11.74% on its transmission assets. 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 Programs (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 the three and nine months ended September 30, 2025, RIE purchased $90 million and $245 million of accounts receivable from alternative suppliers. During the three and nine months ended September 30, 2024, RIE purchased $80 million and $234 million of accounts receivable from alternative suppliers. During the three and nine months ended September 30, 2025, PPL Electric purchased $439 million and $1.3 billion of accounts receivable from alternative suppliers. During the three and nine months ended September 30, 2024, PPL Electric purchased $404 million and $1.2 billion of accounts receivable from alternative suppliers.

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