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Utility Rate Regulation | 6 Months Ended
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Jun. 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
| June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024
Current Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rate adjustment mechanisms | $ | 99 |  |  | $ | 95 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Renewable energy certificates | 21 |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm damage expense rider | 45 |  |  | 68 |  |  | 45 |  |  | 68 |  |  | — |  |  | — |  |  | — |  |  | — |
Gas supply clause | 20 |  |  | 3 |  |  | — |  |  | — |  |  | 20 |  |  | 3 |  |  | — |  |  | — |
Transmission service charge | 52 |  |  | 44 |  |  | — |  |  | 27 |  |  | — |  |  | — |  |  | — |  |  | — |
DSIC | 9 |  |  | 8 |  |  | 9 |  |  | 8 |  |  | — |  |  | — |  |  | — |  |  | — |
TCJA customer refund and recovery | 30 |  |  | 21 |  |  | 30 |  |  | 21 |  |  | — |  |  | — |  |  | — |  |  | — |
ISR deferral | 6 |  |  | 22 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 21 |  |  | 45 |  |  | 8 |  |  | 9 |  |  | 6 |  |  | 5 |  |  | — |  |  | 1 |
Total current regulatory assets | $ | 303 |  |  | $ | 320 |  |  | $ | 92 |  |  | $ | 133 |  |  | $ | 26 |  |  | $ | 8 |  |  | $ | — |  |  | $ | 1 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Defined benefit plans | $ | 959 |  |  | $ | 967 |  |  | $ | 471 |  |  | $ | 473 |  |  | $ | 219 |  |  | $ | 226 |  |  | $ | 150 |  |  | $ | 149 |
Plant outage costs | 27 |  |  | 30 |  |  | — |  |  | — |  |  | 6 |  |  | 7 |  |  | 21 |  |  | 23 |
Net metering | 159 |  |  | 147 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Environmental cost recovery | 96 |  |  | 96 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm costs | 114 |  |  | 113 |  |  | 42 |  |  | 22 |  |  | 24 |  |  | 20 |  |  | 37 |  |  | 29 |
Unamortized loss on debt | 19 |  |  | 20 |  |  | 3 |  |  | 3 |  |  | 9 |  |  | 9 |  |  | 6 |  |  | 6 |
Terminated interest rate swaps | 49 |  |  | 53 |  |  | — |  |  | — |  |  | 29 |  |  | 31 |  |  | 20 |  |  | 22 |
Accumulated cost of removal of utility plant | 168 |  |  | 173 |  |  | 168 |  |  | 173 |  |  | — |  |  | — |  |  | — |  |  | — |
AROs | 275 |  |  | 280 |  |  | — |  |  | — |  |  | 76 |  |  | 75 |  |  | 199 |  |  | 205 |
RAR | 80 |  |  | 83 |  |  | — |  |  | — |  |  | 80 |  |  | 83 |  |  | — |  |  | — |
Gas line inspections | 24 |  |  | 24 |  |  | — |  |  | — |  |  | 22 |  |  | 22 |  |  | 2 |  |  | 2 |
Advanced metering infrastructure | 35 |  |  | 28 |  |  | — |  |  | — |  |  | 18 |  |  | 14 |  |  | 17 |  |  | 14 |
Other | 50 |  |  | 46 |  |  | 8 |  |  | 2 |  |  | 5 |  |  | 4 |  |  | 10 |  |  | 8 |
Total noncurrent regulatory assets | $ | 2,055 |  |  | $ | 2,060 |  |  | $ | 692 |  |  | $ | 673 |  |  | $ | 488 |  |  | $ | 491 |  |  | $ | 462 |  |  | $ | 458 |
| PPL |  | PPL Electric |  | LG&E |  | KU
| June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024
Current Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Generation supply charge | $ | 44 |  |  | $ | 52 |  |  | $ | 44 |  |  | $ | 52 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
ECR | 6 |  |  | 12 |  |  | — |  |  | — |  |  | 4 |  |  | 6 |  |  | 2 |  |  | 6 |
Transmission formula rate | 19 |  |  | 1 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Rate adjustment mechanisms | 64 |  |  | 71 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency | 27 |  |  | 25 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
DSM | 24 |  |  | 17 |  |  | — |  |  | — |  |  | 10 |  |  | 7 |  |  | 14 |  |  | 10 |
Revenue decoupling mechanism | 42 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Gas cost recovery | 21 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 26 |  |  | 35 |  |  | 8 |  |  | 5 |  |  | 1 |  |  | 1 |  |  | 7 |  |  | 6 |
Total current regulatory liabilities | $ | 273 |  |  | $ | 223 |  |  | $ | 62 |  |  | $ | 57 |  |  | $ | 15 |  |  | $ | 14 |  |  | $ | 23 |  |  | $ | 22 |
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 1,038 |  |  | $ | 1,022 |  |  | $ | — |  |  | $ | — |  |  | $ | 324 |  |  | $ | 314 |  |  | $ | 410 |  |  | $ | 408 |
Net deferred taxes | 1,851 |  |  | 1,899 |  |  | 721 |  |  | 739 |  |  | 428 |  |  | 439 |  |  | 484 |  |  | 498 |
Defined benefit plans | 307 |  |  | 294 |  |  | 110 |  |  | 100 |  |  | 24 |  |  | 24 |  |  | 66 |  |  | 65 |
Terminated interest rate swaps | 52 |  |  | 54 |  |  | — |  |  | — |  |  | 26 |  |  | 27 |  |  | 26 |  |  | 27 |
Energy efficiency | 30 |  |  | 16 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 57 |  |  | 50 |  |  | — |  |  | — |  |  | 11 |  |  | 11 |  |  | 17 |  |  | 11 |
Total noncurrent regulatory liabilities | $ | 3,335 |  |  | $ | 3,335 |  |  | $ | 831 |  |  | $ | 839 |  |  | $ | 813 |  |  | $ | 815 |  |  | $ | 1,003 |  |  | $ | 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) 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, 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. An evidentiary hearing was held on July 18, 2025. The Hearing Officer granted the Attorney General of Rhode Island's request for a continuance of the hearing until August 8, 2025 to allow for review and consideration of the calculations of the net present value of the obligation and bill credits. PPL cannot predict the outcome of these proceedings. 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 return on equity of 10.95%. Subject to KPSC approval, the requested rates are expected to become effective on January 1, 2026. Certain counterparties have intervened in the proceedings. Data discovery and the filing of written testimony will continue through the third quarter of 2025 and a hearing in the matter has been scheduled for November 3, 2025. A ruling from the KPSC is expected during the fourth quarter of 2025. 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 do 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 natural gas combined cycle (NGCC) generation unit at KU's E.W. Brown station, •to build a 645 MW NGCC generation unit at LG&E's Mill Creek station, •to build a four-hour 400 MW (1,600 MWh total) battery energy storage system (BESS) at LG&E's Cane Run station, and •to build a selective catalytic reduction (SCR) environmental facility at KU’s Ghent station 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 NGCC unit is in addition to a new NGCC unit currently under construction at that location. The filing also notes projected in service dates for the projects, including the E.W. Brown NGCC unit in 2030, the Mill Creek NGCC unit in 2031, the Cane Run BESS in 2028 and the Ghent SCR facility 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. 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: (a) a 645 MW NGCC generation unit at KU’s E.W. Brown station; (b) a 645 MW NGCC at LG&E’s Mill Creek station; and (c) a SCR environmental facility at KU’s Ghent station Unit 2. 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 NGCC would be recovered through a new rate tracker mechanism, and the retirement date for the existing Mill Creek Unit 2 would be extended from 2027 to the operational date of the proposed Mill Creek 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. A hearing in the matter has been scheduled to begin on August 4, 2025. LG&E and KU anticipate a ruling from the KPSC during the fourth quarter of 2025. PPL, LG&E and KU cannot predict the outcome of the 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 June 30, 2025, LG&E and KU 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. Mill Creek Unit 2 is currently expected to be retired in 2027. 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 $208 million at June 30, 2025 and LG&E is continuing to depreciate using the current approved rates through its anticipated retirement date in 2027. LG&E expects to reclassify the net book value remaining at retirement, which is expected to total approximately $161 million, 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) 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. Oral argument before the D.C. Circuit Court of Appeals occurred on January 21, 2025. 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 base rates increases, provided, however, that increases associated with the FERC's May 18, 2023 order are expected to be subject to future rate 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 return on equity (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 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 the three and six months ended June 30, 2025, RIE purchased $68 million and $155 million of accounts receivable from alternative suppliers. During the three and six months ended June 30, 2024, RIE purchased $44 million and $95 million of accounts receivable from alternative suppliers. During the three and six months ended June 30, 2025, PPL Electric purchased $345 million and $811 million of accounts receivable from alternative suppliers. During the three and six months ended June 30, 2024, PPL Electric purchased $348 million and $767 million of accounts receivable from alternative suppliers.

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