Utility Rate Regulation

3 Months Ended

Mar. 31, 2025

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
	March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024
Current Regulatory Assets:


Rate adjustment mechanisms	$	74	$	95	$	—	$	—	$	—	$	—	$	—	$	—

Renewable energy certificates	16		14		—		—		—		—		—		—



Storm damage expense rider	46		68		46		68		—		—		—		—
Gas supply clause	23		3		—		—		23		3		—		—

Transmission service charge	35		44		—		27		—		—		—		—
Transmission formula rate	13		14		3		2		—		—		—		—
DSIC	9		8		9		8		—		—		—		—
TCJA customer refund and recovery	28		21		28		21		—		—		—		—
ISR deferral	10		22		—		—		—		—		—		—
Gas line tracker	5		4		—		—		5		4		—		—
Other	15		27		8		7		3		1		—		1
Total current regulatory assets	$	274	$	320	$	94	$	133	$	31	$	8	$	—	$	1


	PPL				PPL Electric				LG&E				KU
	March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024

Noncurrent Regulatory Assets:
Defined benefit plans	$	962	$	967	$	472	$	473	$	223	$	226	$	147	$	149
Plant outage costs	29		30		—		—		7		7		22		23
Net metering	147		147		—		—		—		—		—		—
Environmental cost recovery	96		96		—		—		—		—		—		—
Storm costs	116		113		41		22		22		20		36		29
Unamortized loss on debt	20		20		3		3		9		9		6		6

Terminated interest rate swaps	51		53		—		—		30		31		21		22
Accumulated cost of removal of utility plant	165		173		165		173		—		—		—		—
AROs	278		280		—		—		76		75		202		205

Retired asset recovery	83		83		—		—		83		83		—		—

Gas line inspections	24		24		—		—		22		22		2		2
Advanced metering infrastructure	31		28		—		—		15		14		16		14
Other	47		46		4		2		4		4		8		8
Total noncurrent regulatory assets	$	2,049	$	2,060	$	685	$	673	$	491	$	491	$	460	$	458


	PPL				PPL Electric				LG&E				KU
	March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024
Current Regulatory Liabilities:
Generation supply charge	$	45	$	52	$	45	$	52	$	—	$	—	$	—	$	—
Environmental cost recovery	9		12		—		—		4		6		5		6



Rate adjustment mechanisms	63		71		—		—		—		—		—		—
Energy efficiency	24		25		—		—		—		—		—		—

DSM	24		17		—		—		10		7		14		10

Revenue decoupling mechanism	40		10		—		—		—		—		—		—
Deferred revenue	25		—		—		—		—		—		—		—
Derivative instruments	15		—		—		—		—		—		—		—
Other	29		36		9		5		2		1		7		6
Total current regulatory liabilities	$	274	$	223	$	54	$	57	$	16	$	14	$	26	$	22

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	1,027	$	1,022	$	—	$	—	$	318	$	314	$	409	$	408

Net deferred taxes	1,875		1,899		729		739		434		439		491		498
Defined benefit plans	296		294		106		100		24		24		66		65
Terminated interest rate swaps	54		54		—		—		27		27		27		27
Energy efficiency	28		16		—		—		—		—		—		—
Other	58		50		—		—		11		11		14		11
Total noncurrent regulatory liabilities	$	3,338	$	3,335	$	835	$	839	$	814	$	815	$	1,007	$	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 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.

Kentucky Activities

(PPL, LG&E and KU)

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.

LG&E and KU anticipate a ruling from the KPSC during the fourth quarter of 2025. 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 this matter. As of March 31, 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 Retired Asset Recovery (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 rider. LG&E expects these costs to be approximately $125 million and proposed to begin application of the RAR rider 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 rider.

Mill Creek Unit 2 is 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 rider. The remaining net book value of Mill Creek Unit 2 was approximately $215 million at March 31, 2025 and LG&E is continuing to depreciate using the current approved rates through its 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 at the time that LG&E expects.

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), 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 recently 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 months ended March 31, 2025 and 2024, RIE purchased $87 million and $51 million of accounts receivable from alternative suppliers.

During the three months ended March 31, 2025 and 2024, PPL Electric purchased $466 million and $419 million of accounts receivable from alternative suppliers.