Utility Rate Regulation - Regulatory Liabilities (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2026

Dec. 31, 2025

Regulatory Liabilities [Line Items]

Current regulatory liabilities

$ 353

$ 376

Noncurrent regulatory liabilities

$ 3,219

3,318

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, 2026		December 31, 2025		September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025
Current Regulatory Assets:


Rate adjustment mechanisms	$	88	$	86	$	—	$	—	$	—	$	—	$	—	$	—

Renewable energy certificates	31		21		—		—		—		—		—		—



Storm damage expense rider	72		53		72		53		—		—		—		—
Gas supply clause	35		10		—		—		35		10		—		—

Transmission service charge	57		61		—		—		—		—		—		—


TCJA	—		40		—		40		—		—		—		—


Other	29		37		12		19		7		9		—		1
Total current regulatory assets	$	312	$	308	$	84	$	112	$	42	$	19	$	—	$	1

Noncurrent Regulatory Assets:
Defined benefit plans	$	935	$	961	$	469	$	477	$	201	$	212	$	140	$	144
Plant outage costs	17		23		—		—		3		5		14		18
Net metering	170		164		—		—		—		—		—		—
Environmental cost recovery	99		102		—		—		—		—		—		—
Storm costs	123		113		52		42		21		24		33		38
Unamortized loss on debt	16		18		2		2		7		8		5		6

Terminated interest rate swaps	45		47		—		—		26		28		19		19
Accumulated cost of removal of utility plant	218		184		218		184		—		—		—		—
AROs	245		263		—		—		69		73		176		190
Derivative instruments	18		3		—		—		—		—		—		—
RAR	69		76		—		—		69		76		—		—

Gas line inspections	23		24		—		—		21		22		2		2
Advanced metering infrastructure	64		67		—		—		27		28		37		39
IT system costs	78		18		36		18		20		—		20		—
TCJA	29		—		29		—		—		—		—		—
Other	41		29		2		2		10		6		9		11
Total noncurrent regulatory assets	$	2,190	$	2,092	$	808	$	725	$	474	$	482	$	455	$	467


	PPL				PPL Electric				LG&E				KU
	September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025
Current Regulatory Liabilities:
Generation supply charge	$	31	$	45	$	31	$	45	$	—	$	—	$	—	$	—
Transmission service charge	1		17		1		17		—		—		—		—
Universal service rider	—		17		—		17		—		—		—		—



Transmission formula rate	126		62		60		23		—		—		—		—
Rate adjustment mechanisms	108		124		—		—		—		—		—		—
Energy efficiency	25		26		—		—		—		—		—		—

DSM	16		21		—		—		6		8		10		13

Revenue decoupling mechanism	29		55		—		—		—		—		—		—


Other	17		9		—		1		5		5		9		3
Total current regulatory liabilities	$	353	$	376	$	92	$	103	$	11	$	13	$	19	$	16

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	1,052	$	1,043	$	—	$	—	$	352	$	334	$	405	$	415

Net deferred taxes	1,713		1,798		679		708		395		415		443		467
Defined benefit plans	329		342		126		120		19		23		65		69
Terminated interest rate swaps	50		52		—		—		25		26		25		26

Advanced metering infrastructure	25		30		—		—		8		10		17		20
Other	50		53		—		—		—		1		—		—
Total noncurrent regulatory liabilities	$	3,219	$	3,318	$	805	$	828	$	799	$	809	$	955	$	997

Below is an update to Note 7 in the Registrants' 2025 Form 10-K for 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."

(All Registrants)

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. As a result of the 2025 Kentucky base rate case proceeding, LG&E and KU agreed to remove from depreciation expense the terminal net salvage component for thermal units. These costs will be recovered when spent upon retirement of the associated generating unit.

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 has typically been included in rates and was amortized over the subsequent five-year period. As a result of the 2025 Pennsylvania base rate case proceeding, effective on July 1, 2026, the deferral is included in rates and amortized over the subsequent ten-year period.

IT System Costs

IT system costs represent expenditures incurred associated with implementing certain information technology investments. The RIPUC, KPSC and PAPUC approved recovery of these costs in the 2025 Rhode Island, Kentucky and Pennsylvania base rate case proceedings. The RIPUC allowed enterprise resource planning implementation operation and maintenance costs incurred after January 1, 2026 to be amortized over a ten-year period, subject to a maximum of approximately $8 million. The KPSC allowed costs to be amortized over a period consistent with the depreciable life of the associated IT system. The PAPUC allowed IT system costs to be capitalized and included in PPL Electric's rate base.

(PPL and PPL Electric)

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. Through June 30, 2026, reportable storm damage expenses to be recovered annually through base rates were set at $20 million. In the 2025 base rate case proceeding, the PAPUC approved reportable storm damage expenses of $32 million to be recovered annually through base rates. The SDER will recover from or refund to customers the applicable expenses from reportable storms as compared to the amount recovered annually through base rates.

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. The impacts of the lower U.S. federal corporate income tax rate are included in base rates effective July 1, 2026. Prior to new base rates going into effect on July 1, 2026, PPL Electric over-refunded customers for the impact of the lower U.S. federal corporate income tax rates. PPL Electric intends to address recovery of this remaining balance in a future proceeding. PPL Electric cannot predict the outcome of that proceeding.

Advanced Metering Infrastructure (AMI) (PPL, LG&E and KU)

In the 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 AFUDC as 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 the 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. AMI regulatory assets approved for base rate recovery are being amortized through 2040 and AMI regulatory liabilities approved for base rate return are being amortized through 2030.

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 sought to implement a two-year rate plan. As submitted in the initial application, in the first year of the rate plan RIE's proposed base distribution rates for electric and gas service were designed to collect additional annual operating revenue of approximately $181 million ($66 million in electricity revenues and $115 million in gas revenues). In the second year of the rate plan, RIE's proposed base distribution rates for electric and gas combined were 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 in electricity revenues and $32 million in gas revenues). The application was based on a historical test year of September 1, 2024 through August 31, 2025 and requested an authorized ROE of 10.75%. The amounts in the initial submission were evaluated after the Hold Harmless Commitment (as defined below) and potential bill credits were consolidated with the base distribution rate proceeding, as discussed below.

On August 21, 2026, the RIPUC approved oral motions in the proceeding. The RIPUC approved certain aspects of RIE's proposals and modified or rejected others. The RIPUC decisions authorized annual revenue increases of $44 million for electric and $94 million for gas, a return on equity of 9.275%, and a debt-to-equity ratio of 48% debt to 52% equity. The RIPUC did not approve a proposed second rate year.

The RIPUC decisions also addressed certain issues regarding the recovery and accounting treatment of certain expenses, directed RIE to propose new performance metrics for certain investments and directed RIE to file a new tariff for extra-large electric loads by December 31, 2026. The RIPUC also approved or accepted several settlement agreements with intervening parties.

In response to the motions, RIE submitted the required compliance filing on August 27, 2026. The approved rate changes were effective as of September 1, 2026. RIE has not received a final written order from the RIPUC as of the filing date of this Form 10-Q. RIE and all intervening parties have the right to appeal once the final written order is issued. RIE will evaluate the details of the written order and related matters, including potential next steps. PPL cannot predict the ultimate outcome of this matter.

Hold Harmless Commitment

As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers (the Division) 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). See "Regulatory Matters - Rhode Island Activities - Hold Harmless Implementation Agreement" in Note 7 in PPL's 2025 Form 10-K for additional information on the filings and other matters related to the Hold Harmless Commitment that occurred in 2025.

On April 16, 2026, RIE filed a motion with the RIPUC to reopen the previous docket concerning the Hold Harmless Commitment along with an updated tariff advice which reflected a methodology consistent with the previously proposed miscellaneous bill credits and two potential, alternative methods of allocating the bill credits among customers. On April 17, 2026, the RIPUC approved the motion and consolidated the tariff advice docket with the pending base distribution rate proceeding. The RIPUC held hearings on the RIE proposal on July 8, 2026.

On August 21, 2026, the RIPUC addressed RIE's proposal with respect to its Hold Harmless Commitment. The RIPUC denied RIE's hold harmless proposal as submitted but authorized an alternative that increases the amount to be provided to customers to approximately $175 million, of which $163 million will be delivered to customers as bill credits and $12 million through a reduction to the gas cost recovery rate adjustment mechanism balance. The Division confirmed that the alternative proposal would fully satisfy RIE's obligation under the Hold Harmless Commitment, and RIE voluntarily accepted the RIPUC's alternative proposal on August 25, 2026. The RIPUC approved the implementing tariff on September 24, 2026. The bill credits will be issued to RIE electric and gas customers from October 2026 through September 2027. RIE will record a reduction of revenue as the bill credits are issued. The reduction of the gas cost recovery rate adjustment mechanism balance was recorded in the third quarter of 2026.

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 will be recovered through the Storm Fund Replenishment factor.

At an Open Meeting on March 31, 2026, the RIPUC approved a provisional Storm Fund Replenishment Factor effective April 1, 2026, and directed that the collections from that factor be used to pay down the remaining balance of the Winter Volatility Credit. The RIPUC also directed RIE to make a filing proposing a new Storm Fund Replenishment Factor to go into effect at the time when the Winter Volatility Credit is expected to be paid down with a goal of having the Storm Fund have a balance of zero at the end of March 2027. That filing was made on June 30, 2026, and proposed a new factor below the current provisional factor. On August 31, 2026, the RIPUC voted to keep the higher provisional factor in place, rather than adopting the lower factor proposed in accordance with the March 31, 2026 order.

FY 2027 Gas ISR Plan

On March 27, 2026, the RIPUC approved a capital budget of $161 million. In addition, the RIPUC approved an operation and maintenance expense budget of $17 million for curb-to-curb paving. On March 31, 2026, the RIPUC approved RIE's compliance filing for rates effective April 1, 2026.

FY 2027 Electric ISR Plan

On March 27, 2026, the RIPUC approved a capital budget of $141 million (including $18 million for Advanced Metering Functionality). In addition, the RIPUC approved an operation and maintenance expense budget of $14 million, primarily for vegetation management. On March 31, 2026, the RIPUC approved RIE's compliance filing for rates effective April 1, 2026.

Kentucky Activities

(PPL, LG&E and KU)

Rate Case Proceedings

On February 16, 2026, the KPSC issued orders approving portions of LG&E's and KU's October 2025 stipulation and recommendation, with modifications. See "Regulatory Matters – Kentucky Activities – Rate Case Proceedings" in Note 7 in PPL's, LG&E's and KU's 2025 Form 10-K for additional information on the filings made by LG&E and KU with the KPSC in 2025.

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 included authorized returns on equity of 9.775% for base rate purposes and 9.675% for capital rate adjustment mechanisms.

The KPSC orders approved 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 Generation Cost Recovery Adjustment Clause 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. LG&E and KU applied refunds to customer accounts for amounts billed in excess of the rates approved by the KPSC.

The KPSC orders did not approve the Sharing Mechanism 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.

On March 11, 2026, LG&E and KU filed a request for rehearing on several issues contained in the orders from the KPSC along with a Notice of their Withdrawal from the stipulation. On March 27, 2026, the KPSC issued orders correcting tariff appendices, denying two intervenor rehearing requests, and reopening the dockets to consider LG&E's and KU's request for rehearing. Following two rounds of additional discovery and the filing of briefs by the parties, on June 20, 2026, the case was submitted for a decision on the record by the KPSC.

On August 14, 2026, the KPSC issued an order relating to LG&E's and KU's requests for rehearing of the KPSC's February 2026 orders granting certain increases in annual electricity and gas revenues and associated accounting and other matters. The KPSC order approved certain elements of the rehearing requests, including matters relating to incorporating regulatory assets and liabilities in rate base calculations and recovery therein, utilizing updated cost estimates in a potential recovery cap in the PGR mechanism, and allowing pre-2026 costs to be included in a regulatory asset relating to LG&E's stay-open costs regarding Mill Creek Unit 2.

The KPSC order denied other elements of the rehearing requests, including seeking reinstatement of certain other aspects of a prior October 2025 stipulation and recommendation of LG&E and KU and certain intervenors in the rate increase proceedings.

LG&E and KU estimate that the KPSC order represents increases of approximately $4 million in annual LG&E electricity and gas revenues and approximately $3 million in annual KU electricity revenues, above the increased amounts contained in the KPSC's February 2026 order. The revised rates are effective for services rendered on and after the date of the order.

Potential Legal Merger of LG&E and KU

Pursuant to prior orders of the KPSC, the LG&E and KU rate case application included an assessment of a potential legal merger of LG&E and KU and concluded a legal merger may be appropriate. On December 30, 2025, LG&E and KU filed a joint update in the rate case proceedings stating that they expected to file necessary applications for merger approval in mid-2026 with the KPSC. On March 31, 2026, LG&E and KU filed an application with the KPSC for approval of the merger and associated accounting, financing and rate mechanism matters. On April 17, 2026, LG&E and KU filed an application with the VSCC for approval of the merger and certain associated matters. On May 29, 2026, LG&E and KU filed a related application with the VSCC for approval of financing and affiliate transactions in connection with the proposed merger. On July 2, 2026, LG&E and KU reached a proposed settlement agreement with the majority of the intervenors in the KPSC proceeding and filed a stipulation and recommendation with the KPSC recommending approval of the merger by the KPSC and including certain LG&E and KU commitments regarding merged LG&E and KU rate transition plans and deferred regulatory asset and liability accounting and rate treatment regarding relevant merger costs and savings and depreciation changes. On July 9, 2026, LG&E and KU filed a Section 203 application with the FERC for approval of the merger.

On August 31, 2026, the VSCC issued an order authorizing the financing and affiliate transaction matters relating to the merger. On September 18, 2026, the FERC issued an order authorizing the merger. On September 23, 2026, the FCC consented to the merger transaction. On September 25, 2026, the KPSC issued an order authorizing the merger and related matters, with certain modifications to the proposed settlement agreement and associated accounting, financing and rate matters. On October 22, 2026, the VSCC issued an order authorizing the merger. The merger remains subject to approvals by internal boards and the sole shareholder of both companies, and the entry by LG&E and KU into the operative merger transactional agreements.

The proposed merger structure contemplates LG&E as the successor legal entity which would, by operation of law, retain and assume, respectively, all the assets, properties and rights, and liabilities, duties and obligations of LG&E and KU. The targeted effective date is January 1, 2027.

PPL, LG&E and KU cannot predict the outcome of this matter.

Mill Creek 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 Unit 2.

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 $183 million at September 30, 2026 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 "Rate Case Proceedings" discussion above for information regarding potential changes in the retirement date of Mill Creek Unit 2.

Virginia Activities

See "Kentucky Activities – Potential Legal Merger of LG&E and KU" above with respect to filing an application with VSCC for approval of a merger between LG&E and KU.

Rate Case Proceeding (PPL and KU)

On April 30, 2026, KU filed a request with the VSCC for an increase in Virginia annual base electricity rates of approximately $19 million. KU's request is based on an authorized 10.95% ROE. On October 1, 2026, the VSCC's staff filed testimony recommending a revenue increase of approximately $12 million based on a 9.80% ROE. Subject to regulatory review and approval, new rates would become effective February 1, 2027. A public hearing is scheduled to commence on November 12, 2026. PPL and KU cannot predict the outcome of this matter.

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 have increased PPL Electric's total annual revenue by approximately 8.6%. The application was based on a fully projected future test year of July 1, 2026 through June 30, 2027 and requested an authorized ROE of 11.3%.

On March 5, 2026, PPL Electric reached a non‑unanimous settlement in principle (the settlement) in its distribution rate case. On March 13, 2026, PPL Electric submitted a joint petition with the PAPUC reflecting the settlement to resolve all issues in PPL Electric's base rate proceeding.

The settlement proposed an annual electric base distribution revenue increase of approximately $275 million and does not stipulate a return on equity or capital structure. As part of the settlement, PPL Electric will not increase distribution base rates for two years from the effective date of the new rates. Additionally, the settlement:

•provides for DSIC eligible capital investment (and associated depreciation and tax effects) to be rolled into base rates, and for the DSIC to be reset to zero, capped at 5.0% of annual distribution revenues, upon implementation of new base rates.

•sets the expense from reportable storms recovered through base rates for the Storm Damage Expense Rider (SDER) at $32 million annually beginning July 1, 2026. To the extent eligible reportable storm expenses are above or below this level, over or under collections would be addressed through the SDER during the applicable recovery period.

•supports capitalization of Information Technology (IT) upgrades for planned system implementations and infrastructure costs for shared IT platforms. The total projected cost of these projects is expected to be $54 million, inclusive of AFUDC, through June 30, 2027.

•supports adoption of a new tariff schedule governing service to certain large load customers (including data centers). This new rate class would provide $11 million in support for PPL Electric's residential low-income program.

•provides for enhancements to Customer Assistance Program processes and customer notifications, an increase to the Low-Income Usage Reduction Program annual budget beginning January 1, 2027 of $1.5 million (to a total of $13.5 million) with a rollover mechanism for unspent amounts, and a waiver of reconnection fees for low-income customers beginning July 1, 2027.

The settlement also contains agreed positions regarding certain other tariff, rate, regulatory accounting and other issues raised in the proceedings, as well as recommending approval of all remaining matters as requested by PPL Electric's rate request.

On June 11, 2026, the PAPUC entered its order approving the settlement with a minor modification related to net metering eligibility. None of the parties to the settlement objected to the PAPUC's minor modification to the settlement terms and new rates became effective on July 1, 2026. On June 26, 2026, the Customer-Generator Coalition filed a Petition for Reconsideration of the June 11, 2026 PAPUC Order, and PPL Electric filed its Answer on July 6, 2026. The PAPUC entered an Order denying the Customer-Generator Coalition’s Petition on August 27, 2026. One member of the Customer-Generator Coalition, Aspen Power Partners, LLC, filed a Petition for Review with the Pennsylvania Commonwealth Court on September 25, 2026, appealing the PAPUC’s August 27, 2026 Order. Aspen Power Partners’ appeal is limited to a net metering eligibility issue, and PPL Electric does not anticipate that the outcome of the Commonwealth Court appeal will have any effect on the rates approved by the PAPUC.

Federal Matters

See "Kentucky Activities – Potential Legal Merger of LG&E and KU" above with respect to the filing of an application with FERC for approval of a potential merger between LG&E and KU.

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, which are underway. In May 2026, the FERC issued an order declaring the transition mechanism agreements effective, subject to refund, and set the proceedings for hearing suspended for settlement.

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.

ISO-NE ROE Complaints (PPL)

Transmission rates for utilities in ISO-NE are subject to a common ROE shared among the New England transmission owners (NETOs). This ROE has been set at 11.14% since 2005. In 2011 through 2016, transmission customer representatives filed four complaints at the FERC seeking to lower it, arguing that an 11.14% ROE was unjust and unreasonable under the Federal Power Act (Section 206).

In 2014, the FERC issued Opinion No. 531 that changed the methodology the FERC uses for determining transmission ROEs. It set the ROE at 10.57% with a maximum ROE including incentives of 11.74%. Two additional FERC orders followed: Opinion No. 531-A (2014) and Opinion No. 531-B (2015). Each maintained the 10.57% ROE. Both the NETOs and customers appealed.

In 2017, the D.C. Circuit Court of Appeals issued an order vacating Opinions Nos. 531, 531-A, and 531-B, and remanding to the FERC for further proceedings. The court found that the FERC had not properly followed Section 206, which required a specific finding that the existing 11.14% ROE was unjust and unreasonable before it could order a new 10.57% ROE. In 2018, the FERC issued an additional order on remand applicable to all four pending complaints, seeking additional briefing.

On March 19, 2026, the FERC issued Opinion No. 594, addressing the outstanding NETO complaint dockets. The FERC ordered NETOs' base ROE be set at 9.57%, with a total or maximum ROE including incentives not to exceed 12.09%, with an effective date of October 16, 2014.

As of September 30, 2026, RIE had a recorded liability of $27 million for the estimated amounts to be refunded as a result of the order.

The FERC initially ordered refunds with interest at the FERC rate to be paid within thirty days. On April 2, 2026, RIE and the other NETOs filed for an extension of the refund period. On April 14, 2026, the FERC issued an order extending the refund period through May 20, 2027.

On April 20, 2026, RIE and the other NETOs filed a request for rehearing of Opinion No. 594, which is a necessary prerequisite to appeal the order. On May 21, 2026, FERC issued a denial of rehearing by operation of law. The FERC issued a substantive order on rehearing, Opinion No. 594-A, on September 24, 2026, which largely upheld the decision in Opinion No. 594, including the reduction of ROE, the methodological determinations, and the refunds. The NETOs, including RIE, filed two appeals with the D.C. Circuit Court of Appeals, on May 18 and June 5, 2026, related to the New England ROE and Opinion No. 594. These appeals remain pending.

Separately, on April 30, 2026, the NETOs, including RIE, filed a Section 205 docket requesting a new base ROE of 11.39% going forward. On June 29, 2026, FERC issued an order accepting the proposed base ROE for filing, suspending the order for the maximum statutory period of five months (effective November 30, 2026), and establishing paper hearing proceedings. These paper hearing proceedings are continuing.

PPL cannot predict the outcome of these matters.

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, 2026, RIE purchased $98 million and $267 million of accounts receivable from alternative suppliers. 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, 2026, PPL Electric purchased $463 million and $1.4 billion 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.

Generation Supply Charge [Member]

Regulatory Liabilities [Line Items]

Current regulatory liabilities

$ 31

Universal Service Rider [Member]

Regulatory Liabilities [Line Items]

Current regulatory liabilities

Accumulated Cost Of Removal Of Utility Plant [Member]

Regulatory Liabilities [Line Items]

Noncurrent regulatory liabilities

1,052

1,043