
	PPL				PPL Electric				LG&E				KU
	June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023
Current Regulatory Assets:


Rate adjustment mechanisms	$	133	$	118	$	—	$	—	$	—	$	—	$	—	$	—

Renewable energy certificates	14		14		—		—		—		—		—		—
Derivative instruments	18		51		—		—		—		—		—		—
Smart meter rider	7		6		7		6		—		—		—		—
Universal service rider	10		—		10		—		—		—		—		—
Storm damage costs	38		12		38		12		—		—		—		—

Fuel adjustment clause	—		4		—		—		—		3		—		—
Transmission service charge	50		43		36		31		—		—		—		—
Transmission formula rate	16		5		—		—		—		—		—		—
Distribution system improvement charge	8		7		8		7		—		—		—		—
Tax Cuts and Jobs Act (over/under)	5		—		5		—		—		—		—		—
Gas line tracker	4		—		—		—		4		—		—		—
Other	32		33		—		1		2		4		1		3
Total current regulatory assets	$	335	$	293	$	104	$	57	$	6	$	7	$	1	$	3

Noncurrent Regulatory Assets:
Defined benefit plans	$	875	$	887	$	417	$	417	$	208	$	217	$	133	$	136
Plant outage costs	34		38		—		—		8		10		26		28
Net metering	141		112		—		—		—		—		—		—
Environmental cost recovery	98		99		—		—		—		—		—		—
Storm costs	111		97		12		—		18		15		17		14
Unamortized loss on debt	22		22		3		3		10		10		7		7
Interest rate swaps	5		7		—		—		5		7		—		—
Terminated interest rate swaps	55		58		—		—		32		34		23		24
Accumulated cost of removal of utility plant	173		178		173		178		—		—		—		—
AROs	286		289		—		—		75		76		211		213

Derivatives instruments	2		8		—		—		—		—		—		—
Gas line inspections	23		21		—		—		21		19		2		2
Advanced metering infrastructure	20		15		—		—		10		7		10		8
Other	44		43		2		—		—		—		7		7
Total noncurrent regulatory assets	$	1,889	$	1,874	$	607	$	598	$	387	$	395	$	436	$	439


	PPL				PPL Electric				LG&E				KU
	June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023
Current Regulatory Liabilities:
Generation supply charge	$	72	$	51	$	72	$	51	$	—	$	—	$	—	$	—
Tax Cuts and Jobs Act customer refund	—		5		—		5		—		—		—		—
Act 129 compliance rider	7		15		7		15		—		—		—		—
Transmission formula rate	9		21		7		18		—		—		—		—
Rate adjustment mechanism	79		72		—		—		—		—		—		—
Energy efficiency	25		23		—		—		—		—		—		—
Gas supply clause	—		15		—		—		—		15				—
DSM	10		1		—		—		4		—		6		1
Fuel adjustment clause	6		—		—		—		—		—		6		—
Other	18		22		—		2		1		1		—		—
Total current regulatory liabilities	$	226	$	225	$	86	$	91	$	5	$	16	$	12	$	1

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	1,017	$	996	$	—	$	—	$	312	$	306	$	405	$	399
Power purchase agreement - OVEC	14		19		—		—		10		13		4		6
Net deferred taxes	1,940		1,977		753		763		450		459		510		523
Defined benefit plans	267		252		87		73		20		20		62		59
Terminated interest rate swaps	56		57		—		—		28		29		28		28
Energy efficiency	20		5		—		—		—		—		—		—
Other	36		34		—		—		2		—		4		3
Total noncurrent regulatory liabilities	$	3,350	$	3,340	$	840	$	836	$	822	$	827	$	1,013	$	1,018

Pursuant to Report and Order No. 23823 issued May 5, 2020, the RIPUC approved the terms of an Amended Settlement Agreement (ASA), reflecting an allowed return on equity (ROE) rate of 9.275% based on a common equity ratio of approximately 51%. RIE is currently in year six of the multi-year rate plan (Rate Plan). On June 30, 2021, the Rhode Island Division of Public Utilities and Carriers consented to an open-ended extension of the term of the Rate Plan. Pursuant to the settlement with the Rhode Island Office of the Attorney General in connection with the acquisition of RIE by PPL, RIE currently does not anticipate filing a new base rate case before October 1, 2025. Pursuant to the open-ended extension, the Rate Year 3 level of base distribution rates under ASA will remain in effect and RIE will continue to operate under the current Rate Plan until a new Rate Plan is approved by the RIPUC.

The ASA includes additional provisions, including (i) an Electric Transportation Initiative (the ET Initiative) to facilitate the growth of Electric Vehicle (EV) adoption and scaling of the market for EV charging equipment to advance Rhode Island's zero emission vehicles and greenhouse gas emissions policy goals, (ii) two energy storage demonstration projects, which are online and fully connected, (iii) a performance incentive for System Efficiency: Annual Megawatt Capacity Savings, which sunset in 2021 and is a tracking and reporting only metric, and (iv) several additional metrics for tracking and reporting purposes only. The RIPUC discussed the ET Initiative at an Open Meeting on August 30, 2022, advising RIE to seek RIPUC authorization to continue the ET Initiative and/or to alter any of the targets established in the ASA for Rate Year 5 and beyond. No votes or official rulings were taken; however, based on this feedback, RIE paused the ET programs in Rate Year 5.

On September 27, 2023, the RIPUC unanimously approved RIE to deploy an AMF-based metering system for the electric distribution business. RIE is authorized to seek recovery of the approved capital investment through the ISR process with an overall multi-year cap on recovery at approximately $153 million, subject to certain terms, conditions and limitations with respect to the potential offsets and recoverability of certain costs. RIE is required to continue spending, even if above the recovery cap, until it achieves the functionalities outlined in the AMF Business Case. RIE filed with the RIPUC (i) an updated electric Service Quality Plan on December 27, 2023 for RIPUC approval and (ii) additional compliance tariff provisions regarding recovery and updated cost schedules to reflect the RIPUC's decision on December 22, 2023 for RIPUC approval. RIE cannot predict the outcome of these matters.

RIE filed a new GMP with the RIPUC on December 30, 2022. The new GMP filing consists of a holistic suite of grid modernization investments that will provide RIE with the tools and capability to manage the electric distribution system more granularly considering a range of distributed energy resources adoption levels, accelerated by Rhode Island's climate mandates, while at the same time maintaining a safe and reliable electric distribution system. The GMP is an informational guidance document that supports the grid modernization investments to be proposed in future electric ISR plans. Consequently, RIE did not request approval from the RIPUC for any specific investments or seek cost recovery as part of the GMP; rather, RIE requested that the RIPUC issues an order affirming RIE's compliance with its obligation to file a GMP that meets the requirements of the ASA. The RIPUC held a status conference on October 26, 2023, to discuss the scope of the RIPUC’s review of the GMP and its potential impact future electric ISR plans. RIE cannot predict the outcome of this matter.

On January 31, 2024, RIE filed a petition with the RIPUC requesting authority to recognize regulatory assets related to credit card, debit card and related fees transactions ("Electronic Transaction Fees") that RIE has waived and will continue to waive pursuant to the RIPUC orders related to COVID-19 impacts. On July 30, 2024, the RIPUC unanimously approved RIE’s request to record a regulatory asset for Electronic Transaction Fees that have been incurred since July 1, 2020 until RIE’s next general rate case or as otherwise determined by the RIPUC. RIE plans to include a proposal as part of its next base distribution rate case for the amortization and recovery of the regulatory assets and to include future Electronic Transaction Fees in base distribution rates.

At an Open Meeting on March 29, 2022, the RIPUC conditionally approved RIE's FY 2023 Gas ISR Plan and associated revenue requirement, subject to further review regarding RIE's Proactive Main Replacement Program and its decision to reconstruct and purchase heating and pressure regulation equipment located at RIE's Wampanoag and Tiverton take stations. In response to RIPUC direction, RIE filed testimony with the RIPUC on May 16, 2022 regarding its replacement of heating and pressure regulation facilities at the Wampanoag and Tiverton take stations and addressing: (i) a cost-benefit analysis arising from RIE's decision to take ownership of the reconstructed take station equipment; (ii) the potential that the benefits derived from the reconstruction and ownership transfer of the take station equipment will not be realized due to the future use of hydrogen or abandonment of the gas system; and (iii) the depreciation and accounting treatment of the reconstructed take station equipment. The RIPUC has not taken any action to date on this issue, including in its recent action on the FY 2025 Gas ISR Plan.

At an Open Meeting on March 29, 2023, the RIPUC approved RIE's FY 2024 Gas ISR Plan with an adjustment to the budget for the Proactive Main Replacement Program category resulting in a total approved FY 2024 Gas ISR Plan of $163 million for capital investment spend. On March 31, 2023, the RIPUC approved RIE's March 30, 2023 compliance filing for rates effective April 1, 2023. Certain open issues regarding the Gas ISR Plan budgetary and reconciliation framework, raised in connection with the FY 2024 Gas ISR Plan, have been resolved in connection with the approval of the FY 2025 Gas ISR Plan, as discussed below.

On December 22, 2023, RIE filed its FY 2025 Gas ISR Plan with the RIPUC with a budget that includes $185 million of capital investment spend, plus up to an additional $11 million of contingency plan spend in light of the Pipeline and Hazardous Materials Safety Administration's potential enactment of regulations during FY 2025 that, if enacted, would significantly alter RIE's leak detection and repair obligations under such regulations. RIE also filed its proposed gas ISR plan budgetary and reconciliation framework, addressing issues raised in connection with its FY 2024 submission, with its FY 2025 ISR Plan. The RIPUC held hearings in March 2024, and on March 26, 2024, approved the plan, including the proposed budgetary and reconciliation framework, with a total approved FY 2025 Gas ISR Plan of $180 million of which $168 million is for capital investment spend and $12 million spend for paving costs as operations and maintenance (O&M), plus the potential additional $11 million available if the above-mentioned regulations are implemented by the Pipeline and Hazardous Materials Safety Administration. On March 28, 2024, the RIPUC approved RIE's compliance filing for rates effective April 1, 2024.

On December 21, 2023, RIE filed its FY 2025 Electric ISR Plan with the RIPUC with a budget that includes $141 million of capital investment spend, $13 million of vegetation O&M spend and $1 million of Other O&M spend. RIE also filed its proposed electric ISR plan budgetary and reconciliation framework, addressing issues raised in connection with its FY 2024 submission, with its FY 2025 ISR Plan. The RIPUC held hearings in March 2024, and on March 26, 2024, approved the plan, including the proposed budgetary and reconciliation framework, with modifications to the proposed capital investment spend, resulting in a total approved FY 2025 Electric ISR Plan of $132 million for capital investment spend, $13 million for vegetation management O&M spend, and $1 million for Other O&M spend. On March 28, 2024, the RIPUC approved RIE's compliance filing for rates effective April 1, 2024.

In May 2024, LG&E and KU experienced significant windstorm activity in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets with total estimated costs incurred through June 30, 2024 of $28 million ($16 million at LG&E and $12 million at KU). On June 13, 2024, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance expenses portion of the costs incurred related to the storm. On July 2, 2024, the KPSC issued an order provisionally approving the request for accounting purposes, noting that approval for recovery would be determined in the future. As of June 30, 2024, LG&E and KU each recorded regulatory assets related to the storm of $4 million. LG&E and KU cannot predict the outcome of this matter.

On December 22, 2023, the KPSC initiated an investigation into the practices of LG&E and KU regarding the provision of electric service from December 23, 2022 through December 25, 2022, during a period of extreme temperatures during Winter Storm Elliott. The investigation is the result of LG&E's and KU's need to implement brief service interruptions to approximately 55,000 customers during this period. The purpose of the investigation is to supplement discovery and examination already completed through LG&E's and KU's CPCN proceedings, a legislative hearing completed in February 2023 and reports completed by the NERC and the FERC related to the issue. Additionally, the investigation will evaluate LG&E's and KU's actions taken, or planned to be taken, since Winter Storm Elliott that affect their ability to provide service during periods of variable weather and power system stress. LG&E and KU believe actions taken during the period under question were necessary and appropriate. Several parties were granted intervenor status for the proceeding and, after completion of written discovery, a hearing on the matter occurred on May 23, 2024. The parties will be filing post-hearing briefs in the coming months, and the case is expected to be submitted for decision on September 21, 2024. LG&E and KU cannot predict the outcome of this matter, and an estimate of the impact, if any, cannot be determined, but LG&E and KU do not believe this matter will have a significant impact on their operations or financial condition.

On January 31, 2023, the PAPUC initiated an investigation focused on billing issues related to estimated, irregular bills and customer service concerns following customer complaints, which for many customers were driven by increased prices for electricity supply. Certain bills issued during the time period of December 20, 2022 through January 9, 2023 were estimated due to a technical issue that prevented PPL Electric from providing actual collected meter data to customer facing and other internal systems. Customers also reported difficulties accessing PPL Electric's website and contacting the customer service call center. The PAPUC’s Bureau of Investigation & Enforcement (I&E) has directed PPL Electric to respond to certain inquiries and document requests. PPL Electric submitted its responses to the information request and cooperated fully with the investigation. PPL Electric reached a Settlement Agreement with I&E on November 21, 2023. In the settlement, PPL Electric agreed to pay a civil penalty of $1 million, make certain remedial improvements to its billing systems and processes, and agreed to not seek recovery for extraordinary costs incurred in responding to or resulting from the billing event. On November 21, 2023, PPL Electric and I&E submitted a Joint Petition for Approval of Settlement to the PAPUC. On January 18, 2024, the PAPUC issued an Order requesting public comment prior to the PAPUC entering a Final Order on the petition. Comments were due on February 28, 2024, and comments were filed by the Office of Consumer Advocate, CAUSE-PA (low-income advocate), and individual customers. On March 19, 2024, PPL Electric filed reply comments. On April 25, 2024, the PAPUC announced at its public meeting that it would be issuing an order approving the Settlement Agreement with modifications. The modifications included converting the $1 million civil penalty to a $1 million donation to PPL Electric’s hardship fund, Operation HELP, and requiring PPL Electric to make various progress reports on efforts to remediate the billing issue. PPL Electric and I&E had 20 business days from the issuance of the PAPUC order to accept or reject the proposed modifications to the Settlement Agreement. The time period to withdraw from the Settlement Agreement expired on June 14, 2024, without PPL Electric or I&E withdrawing from the Settlement Agreement, and the terms of the Settlement Agreement, as modified by the PAPUC’s order, are now final. PPL Electric is in the process of complying with the terms of the Settlement Agreement, including making the $1 million contribution to Operation HELP on June 24, 2024.

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. FERC issued the substantive order on rehearing on March 21, 2024, reaffirming its prior decision. LG&E and KU filed their opening brief with the D.C. Circuit Court of Appeals on June 24, 2024. 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.

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 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 NETO 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.

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 and six months ended June 30, 2024, PPL Electric purchased $348 million and $767 million of accounts receivable from alternative suppliers. During the three and six months ended June 30, 2023, PPL Electric purchased $374 million and $732 million of accounts receivable from alternative suppliers.