Commitments and Contingencies

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

12. Commitments and Contingencies

Energy Purchase Commitments

(PPL, LG&E and KU)

LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's retail natural gas supply operations. These contracts include the following commitments:


Contract Type			Maximum Maturity Date
Natural Gas Fuel			2027
Natural Gas Retail Supply			2026
Coal			2030
Coal Transportation and Fleeting Services			2033
Natural Gas Transportation			2055

LG&E and KU have a PPA with OVEC expiring in June 2040. See footnote (d) to the table in "Guarantees and Other Assurances" below for information on the OVEC power purchase contract. Future obligations for power purchases from OVEC are demand payments, comprised of debt-service payments and contractually-required reimbursements of plant operating, maintenance and other expenses, and are projected as follows:


	LG&E		KU		Total
2026	$	19	$	8	$	27
2027	24		10		34
2028	24		11		35
2029	25		11		36
2030	23		10		33
Thereafter	184		83		267
Total	$	299	$	133	$	432

LG&E and KU had total energy purchases under the OVEC PPA for the years ended December 31 as follows:


	2025		2024		2023
LG&E	$	26	$	21	$	20
KU	11		9		9
Total	$	37	$	30	$	29

(PPL)

RIE enters into purchase contracts to supply electricity for electricity distribution operations and for the delivery, storage and supply of natural gas for RIE's retail natural gas operations.

These contracts include the following commitments:


Contract Type			Maximum Maturity Date
Electric power			2027
Gas-related			2043

RIE's commitments under these long-term contracts subsequent to December 31, 2025 are summarized in the table below.


	Total		2026		2027-2028		2029-2030		Thereafter

Energy Purchase Obligations	$	939	$	268	$	199	$	126	$	346

Long-term Contracts for Renewable Energy (PPL)

Several of the obligations included in the table above relate to certain long-term contracts for renewable energy, including:

•the Deepwater Wind PPA, a small-scale renewable energy generation project of up to eight offshore wind turbines with an aggregate nameplate capacity of up to 30 MW to benefit the Town of New Shoreham and an underwater cable to Block Island, placed into service in 2016;

•the Three-State Procurement, involving six clean energy long-term contracts pursuant to the Rhode Island Long-Term Contracting Standard (LTCS) of which approximately 36 MW is currently operational and with respect to which RIE collects 2.75% remunerations in the annual payments pursuant to the LTCS; and

•the Offshore Wind Energy Procurement, pursuant to a 20-year PPA with Deep Water Wind Rev I, LLC (Revolution Wind), with an expected nameplate capacity of 407 MW and is expected to be operational in 2026; this contract was approved without remuneration but allows RIE to seek costs incurred under the agreement.

In addition, RIE is obligated under the LTCS (as amended in 2014) to annually solicit for renewable projects until 90 MW of renewable contracting capacity has been secured. The RIPUC-approved solicitations currently in service include: (i) a 15-year PPA with Orbit Energy Rhode Island, LLC for a 3.2 MW nameplate anaerobic digester biogas project located in Johnston, Rhode Island, placed in service in 2017, (ii) a 15-year PPA with Black Bear Development Holdings, LLC for a 3.9 MW nameplate run-of-river hydroelectric plant located in Orono, Maine, placed in service in 2013, (iii) a 15-year PPA with Copenhagen Wind Farm, LLC for an 80 MW nameplate land-based wind project located in Denmark, New York, placed in service in 2018, and (iv) a 15-year PPA with Rhode Island LFG Genco, LLC for a 32.1 MW nameplate combined cycle combustion turbine generating facility fueled by a landfill gas project located in Johnston, Rhode Island, placed in service in 2013. On December 23, 2025, the RIPUC approved the RFP for soliciting renewable energy under LTCS. Under the approved schedule, the RFP will be released, and the solicitation will commence on May 13, 2026 with the deadline for the submission of bids proposals on August 12, 2026.

In addition to the LTCS, on December 19, 2025, RIE along with state agencies and utilities in Maine, Massachusetts, Connecticut and Vermont, released a multi-state RFP to identify competitive proposals for renewable energy and associated transmission infrastructure in Northern Maine under the Affordable Clean Energy Security Act (ACES), as amended in 2022. Bids are due at the end of February 2026 and the selection process will conclude in the third quarter of 2026.

As approved by the RIPUC, RIE is allowed to pass through commodity-related/purchased power costs to customers and collect remuneration equal to 2.75% for long-term contracts approved prior to January 1, 2022, pursuant to LTCS as amended in 2022, and that have achieved commercial operation. For long-term contracts approved pursuant to LTCS or ACES, both as amended, on or after January 1, 2022, RIE is entitled to financial remuneration equal to 1.0% through December 31, 2026, for those projects that are commercially operating. For long-term contracts approved pursuant to LTCS or ACES on or after January 1, 2027, RIE is not entitled to any financial remuneration, unless otherwise granted by the RIPUC. Also, the 2022 amendments to LTCS and ACES added a provision, which provides that for any calendar year in which RIE's actual return on equity exceeds the return on equity allowed by the RIPUC in the last general rate case, the RIPUC may adjust any or all remuneration to assure that such remuneration does not result in or contribute toward RIE earning above its allowed return for such calendar year.

Legal Matters

(All Registrants)

PPL and its subsidiaries are involved in legal proceedings, claims and litigation in the ordinary course of business. PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.

Narragansett Electric Litigation (PPL)

Energy Efficiency Programs Investigation

Narragansett Electric, while under the ownership of National Grid, performed an internal investigation into conduct associated with its energy efficiency programs. On June 27, 2022, the RIPUC opened a new docket (RIPUC Docket No. 22-05-EE) to investigate RIE's actions and the actions of employees of National Grid USA and affiliates during the time RIE was a National Grid USA affiliate being provided services by National Grid USA Service Company, Inc. relating to the manipulation of the reporting of invoices affecting the calculation of past energy efficiency shareholder incentives and the resulting impact on customers. The Rhode Island Attorney General and National Grid USA intervened in the docket and the Rhode Island Division of Public Utilities and Carriers (the Division) is an automatic party in the docket.

On February 21, 2025, the Division filed testimony confirming its initial testimony that $12 million is the appropriate amount to be refunded to the energy efficiency program. On March 4, 2025, a Settlement Agreement between RIE, the Division, and the Rhode Island Attorney General was filed with the RIPUC requiring refunds of $10 million. Of this amount, $2 million has already been refunded through the energy efficiency mechanism with the remaining $8 million to reduce the storm cost regulatory asset recorded on PPL's balance sheet. The settlement also included reimbursement of minor consulting fees and various other compliance actions. On March 5, 2025, the RIPUC approved the Settlement Agreement.

E.W. Brown Environmental Assessment (PPL and KU)

KU is undertaking extensive remedial measures at the E.W. Brown plant including closure of the former ash pond, implementation of a groundwater remedial action plan and performance of a corrective action plan including aquatic study of adjacent surface waters and risk assessment. The aquatic study and risk assessment are being undertaken pursuant to a 2017 Agreed Order with the Kentucky Energy and Environment Cabinet (KEEC). KU conducted sampling of Herrington Lake in 2017 and 2018. In June 2019, KU submitted to the KEEC the required aquatic study and risk assessment, conducted by an independent third-party consultant, finding that discharges from the E.W. Brown plant have not had any significant impact on Herrington Lake and that the water in the lake is safe for recreational use and meets safe drinking water standards. On May 31, 2021, the KEEC approved the report and released a response to public comments. On August 6, 2021, KU submitted a Supplemental Remedial Alternatives Analysis report to the KEEC that outlines proposed additional fish, water, and sediment testing. On February 18, 2022, the KEEC provided approval to KU to proceed with the proposed sampling, which commenced in the spring of 2022. On November 17, 2022, KU submitted a Supplemental Performance Monitoring Report to the KEEC finding that there are no significant unaddressed risks to human health or the environment at the plant. KU revised the Supplemental Performance Monitoring Report on June 8, 2023, in response to KEEC comments from April 24, 2023. On September 1, 2023, the KEEC requested KU to propose additional monitoring or remedial measures. KU submitted a revised Supplemental Performance Monitoring and Corrective Action Completion on December 28, 2023. In August 2024, KU submitted a proposed environmental covenant to the KEEC specifying certain site restrictions. Discussions between KU and the KEEC are ongoing, but KU cannot predict the outcome of this matter.

(PPL, LG&E and KU)

EPA Deregulatory Initiative

On March 12, 2025, the EPA announced a plan to reconsider 31 environmental rules including the Section 111 performance standards and emissions limits for greenhouse gases, the endangerment finding for greenhouse gases, the Good Neighbor Plan, the Mercury and Air Toxics Standards, revisions to the fine particulate matter standard, the ELGs, and the CCRs Rule. Supplementing previous Executive Orders directing various regulatory changes, on April 9, 2025, President Trump issued an Executive Order and Presidential Memorandum directing review of existing rules, repeal of unlawful rules, and initiation of a zero-based budgeting process by which certain rules would automatically expire unless extended. While the current Presidential administration may seek to implement some regulatory changes outside of the rulemaking process, changes to existing rules are generally expected to require formal rulemaking proceedings. Any final EPA actions repealing or revising current rules will likely result in legal challenges. PPL, LG&E, and KU are unable to predict future regulatory changes, if any, that may result from the EPA's deregulatory plan or the outcome of any associated legal challenges. PPL, LG&E, and KU are closely monitoring the ongoing EPA initiative and any related litigation for the impact to our business including planned capital expenditures to comply with the EPA rules.

Water/Waste

ELGs

In 2015, the EPA finalized ELGs for wastewater discharge permits for new and existing steam electricity generating facilities. These guidelines require deployment of additional control technologies providing physical, chemical and biological treatment and mandate operational changes including "zero discharge" requirements for certain wastewaters. The implementation date for individual generating stations was to be determined by the states on a case-by-case basis according to criteria provided by the EPA. In September 2017, the EPA issued a rule to postpone the compliance date for certain requirements. In October 2020, the EPA issued revisions to its best available technology standards for certain wastewaters and potential extensions to compliance dates (the Reconsideration Rule). On May 9, 2024, the EPA issued a final rule modifying the 2020 ELG revisions. The rule increases the stringency of previous control technology and zero discharge requirements, revises certain exemptions for generating units planned for retirement, and requires case-by-case limitations for legacy wastewaters based on the best professional judgment of the state regulators. Legal challenges to the final rule have been consolidated before the U.S. Court of Appeals for the Eighth Circuit. The final rule could potentially result in significant operational changes and additional controls for LG&E and KU plants, but in March 2025 the EPA announced its plan to reconsider the rule. The ELGs are expected to be implemented by the states or applicable permitting authorities in the course of their normal permitting activities. Certain costs are included in the Registrants' capital plans and expected to be recovered from customers through rate recovery mechanisms, but additional costs and recovery will depend on further regulatory developments at the state level. On December 31, 2025, the EPA issued a final rule extending the retirement exemption category application deadline an additional six years, from December 2025 to December 2031 and a five-year extension to the zero liquid discharge deadlines, from December 2029 to December 2034. The EPA announced that it will conduct a technology review of the zero liquid discharge technology in a future rulemaking.

CCRs

In 2015, the EPA issued a final rule governing management of CCRs, which include fly ash, bottom ash and sulfur dioxide scrubber wastes (2015 CCR Rule). The 2015 CCR Rule imposed extensive new requirements for certain CCR impoundments and landfills, including public notifications, location restrictions, design and operating standards, groundwater monitoring and corrective action requirements, and closure and post-closure care requirements, and specifies restrictions relating to the beneficial use of CCRs. In January 2022, the EPA issued several proposed regulatory determinations, facility notifications, and public announcements which indicate increased scrutiny by the EPA to determine the adequacy of measures taken by facility owners and operators to achieve closure of CCR surface impoundments and landfills. In particular, the agency indicated that it will focus on certain practices which it views as posing a threat of continuing groundwater contamination. On May 8, 2024, the EPA issued a final rule (2024 CCR Rule) establishing regulatory requirements for inactive surface impoundments at inactive electricity generation facilities (legacy impoundments). The 2024 CCR Rule also establishes identification, groundwater monitoring, corrective action, closure, and post-closure care requirements for all CCR management units, as defined in the rule, at regulated CCR facilities regardless of how or when the CCR was placed. The rule also requires LG&E and KU to complete applicability determinations, implement site security measures, initiate weekly inspections and monthly monitoring of the impoundment, create a website, and complete hazard assessments and reports for its legacy impoundments. Additionally, the rule could potentially subject CCR management units that have previously completed remedial action and closure and certain beneficial use projects to additional federal regulatory requirements. Legal challenges to the rule have been filed in the D.C. Circuit Court. In March 2025, the EPA announced its plan to update the rule. On July 22, 2025, the EPA published a proposed rule to extend the deadline for select CCR management units for the Facility Evaluation Report Part 1 and Part 2 by one year to February 2027 and February 2028, respectively. The proposed rule would also extend the groundwater monitoring deadline to August 8, 2030, with the initial groundwater monitoring report extended to January 31, 2031.

In connection with the 2015 CCR Rule, LG&E and KU recorded adjustments to existing AROs beginning in 2015. In connection with the 2024 CCR Rule, in the second quarter of 2024, LG&E and KU recognized ARO obligations related to preliminary risk assessments, facility evaluations, feasibility studies and sampling. See Note 18 for additional information. The results of those evaluations, as well as future guidance, regulatory determinations, rulemakings, implementation determinations and other developments could potentially require revisions to current LG&E and KU compliance plans including additional monitoring and remediation at surface impoundments and landfills, the cost of which could be material. PPL, LG&E and KU are unable to predict the outcome of the ongoing litigation, rulemaking, and regulatory determinations or potential impacts on current LG&E and KU compliance plans. PPL, LG&E and KU are currently finalizing or revising closure plans and schedules in accordance with applicable regulations and further material changes to AROs, current capital plans or operating costs may be required as estimates are refined based on closure developments, groundwater monitoring results, and regulatory or legal proceedings. Costs relating to this rule are expected to be subject to rate recovery.

LG&E and KU received KPSC approval for a compliance plan associated with the 2015 CCR Rule providing for the closure of impoundments at the Mill Creek, Trimble County, E.W. Brown, and Ghent stations, and construction of process water management facilities at those plants. In addition to the foregoing measures required for compliance with the federal CCR Rule, KU also received KPSC approval for its plans to close impoundments at the retired Green River, Pineville and Tyrone plants to comply with applicable state law. LG&E and KU have completed planned closure measures at most of the subject impoundments and have commenced post closure groundwater monitoring as required at those facilities. Associated costs are subject to rate recovery through the Companies' ECR adjustment clause.

Superfund and Other Remediation

(All Registrants)

The Registrants are potentially responsible for investigating and remediating contamination under the federal Superfund program and similar state programs. Actions are under way at certain sites including former manufactured gas plants in Pennsylvania, Rhode Island and Kentucky previously owned or operated by, or currently owned by predecessors or affiliates of, PPL subsidiaries.

Depending on the outcome of investigations at identified sites where investigations have not begun or been completed, or developments at sites for which information is incomplete, additional costs of remediation could be incurred. PPL, PPL Electric, LG&E and KU lack sufficient information about such additional sites to estimate any potential liability or range of reasonably possible losses, if any, related to these sites. Such costs, however, are not currently expected to be significant.

The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of manufactured gas plant operations. As a result, individual states may establish stricter standards for water quality and soil cleanup, that could require several PPL subsidiaries to take more extensive assessment and remedial actions at former manufactured gas plants. The Registrants cannot reasonably estimate a range of possible losses, if any, related to these matters.

(PPL and PPL Electric)

PPL Electric is a potentially responsible party for a share of clean-up costs at certain sites. Cleanup actions have been or are being undertaken at these sites as requested by governmental agencies, the costs of which have not been and are not expected to be significant to PPL Electric.

At December 31, 2025 and December 31, 2024, PPL Electric had a recorded liability of $8 million and $8 million, representing its best estimate of the probable loss incurred to remediate these sites.

(PPL)

RIE is a potentially responsible party for a share of clean-up costs at certain sites including former manufactured gas plant facilities formerly owned by the Blackstone Valley Gas and Electric Company and the Rhode Island gas distribution assets of the New England Gas division of Southern Union Company and electric operations at certain RIE facilities. RIE is currently investigating and remediating, as necessary, those sites and certain other properties under agreements with governmental agencies, the costs of which have not been and are not expected to be significant to PPL.

At December 31, 2025 and December 31, 2024, RIE had a recorded liability of $98 million and $98 million, representing its best estimate of the remaining costs of environmental remediation activities. These undiscounted costs are expected to be incurred over approximately 30 years and to be subject to rate recovery. However, remediation costs for each site may be materially higher than estimated, depending on changing technologies and regulatory standards, selected end uses for each site, and actual environmental conditions encountered. RIE has recovered amounts from certain insurers and potentially responsible parties, and, where appropriate, may seek additional recovery from other insurers and potentially responsible parties, but it is uncertain whether, and to what extent, such efforts will be successful.

The RIPUC has approved two settlement agreements that provide for rate recovery of qualified remediation costs of certain contaminated sites located in Rhode Island and Massachusetts. Rate-recoverable contributions for electric operations of approximately $3 million are added annually to RIE's Environmental Response Fund, established with RIPUC approval in March 2000 to address such costs, along with interest and any recoveries from insurance carriers and other third-parties. In addition, RIE recovers approximately $1 million annually for gas operations under a distribution adjustment charge in which the qualified remediation costs are amortized over 10 years. See Note 7 for additional information on RIE's recorded environmental regulatory assets and liabilities.

Regulatory Issues

See Note 7 for information on regulatory matters related to utility rate regulation.

Electricity - Reliability Standards

The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk electric system in North America. The FERC oversees this process and independently enforces the Reliability Standards.

The Reliability Standards have the force and effect of law and apply to certain users of the bulk electric system, including electric utility companies, generators and marketers. Under the Federal Power Act, the FERC may assess civil penalties for certain violations.

PPL Electric, LG&E, KU and RIE monitor their compliance with the Reliability Standards and self-report or self-log potential violations of applicable reliability requirements whenever identified, and submit accompanying mitigation plans, as required. The resolution of a small number of potential violations is pending. Penalties incurred to date have not been significant. Any Regional Reliability Entity determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC.

In the course of implementing their programs to ensure compliance with the Reliability Standards by those PPL affiliates subject to the standards, certain other instances of potential non-compliance may be identified from time to time. The Registrants cannot predict the outcome of these matters, and an estimate or range of possible losses cannot be determined.

Gas - Security Directives (PPL and LG&E)

In May and July of 2021, the Department of Homeland Security's (DHS) Transportation Security Administration issued two security directives applicable to certain notified owners and operators of natural gas pipeline facilities (including local distribution companies) that the Transportation Security Administration has determined to be critical. Both security directives have been updated and extended multiple times. The Transportation Security Administration has determined that LG&E is within the scope of the directives, while RIE has not been notified of this distinction. The first directive, most recently updated and now effective through January 2027, requires notified owners/operators to report specified cybersecurity incidents to the DHS, designate a cybersecurity coordinator, and perform a gap assessment of current entity cybersecurity practices against certain voluntary Transportation Security Administration security guidelines and report results and proposed mitigation to the DHS. The second security directive, updated and effective through May 2026, requires refinement of a Transportation Security Administration-approved Cybersecurity Implementation Plan (CIP) and the Cybersecurity Assessment Plan (CAP). The Transportation Security Administration has transitioned to a performance‑based regulatory model, requiring operators to meet defined cybersecurity outcomes rather than implement prescriptive controls. Key requirements now include: maintaining a Transportation Security Administration‑approved CIP; reporting significant cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (CISA) within 24 hours; completing annual CAPs with all CIP measures assessed on a three‑year cycle; conducting annual testing of at least two Cybersecurity Incident Response Plan (CIRP) objectives; meeting new 2026 vetting requirements for non‑U.S. citizen cybersecurity coordinators (who must participate in a trusted traveler program); and complying with clarified rules governing shared responsibilities when third parties support pipeline operations. LG&E does not believe these security directives or their updates have had, or are expected to have, a material impact on its operations or financial condition.

Other

Guarantees and Other Assurances

(All Registrants)

In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. Examples of such agreements include: guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage.

(PPL)

PPL fully and unconditionally guarantees all of the debt securities and loan obligations of PPL Capital Funding.

(All Registrants)

The table below details guarantees provided as of December 31, 2025. "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee. The Registrants believe the probability of expected payment/performance under each of these guarantees is remote, except for the guarantee related to the payment obligations of Safari under certain sale/leaseback financing transactions and PPL's agreement to fund any increases in the fair value of those obligations, which PPL believes are reasonably possible of occurring. For reporting purposes, on a consolidated basis, the guarantees of PPL include the guarantees of its subsidiary Registrants.


	Exposure at December 31, 2025			Expiration Date
PPL
Indemnifications related to certain tax liabilities related to the sale of the U.K. utility business	£	50	(a)	2028
PPL guarantees related to certain sale/leaseback financing transactions related to the sale of Safari Holdings	$	71	(b)	2028
Indemnifications for losses suffered related to items not covered by Aspen Power's representation and warranty insurance associated with the sale of Safari Holdings	140		(c)	2028
LG&E and KU
LG&E and KU obligation of shortfall related to OVEC			(d)

(a)PPL WPD Limited entered into a Tax Deed dated June 9, 2021 in which it agreed to a tax indemnity regarding certain potential tax liabilities of the entities sold with respect to periods prior to the completion of the sale, subject to customary exclusions and limitations. Because National Grid Holdings One plc, the buyer, agreed to purchase indemnity insurance, the amount of the cap on the indemnity for these liabilities is £1, except with respect to certain surrenders of tax losses, for which the amount of the cap on the indemnity is £50 million. In June 2025, the indemnifications were novated to PPL Energy Holdings.

(b)PPL guaranteed the payment obligations of Safari under certain sale/leaseback financing transactions executed by Safari. These guarantees will remain in place until Safari exercises its option to buy-out the projects under the sale/leaseback financings by the year 2028. Safari will indemnify PPL for any payments made by PPL or claims against PPL under the sale/leaseback transaction guarantees up to $25 million.

Separately, PPL has agreed to fund incremental payment obligations under the buy-outs resulting from increases in the fair market value of the projects from the initial fair market value determined at the time of PPL's sale of Safari Holdings to the time the buy-out options are exercised by Safari. As of December 31, 2025, PPL cannot reasonably estimate its payment obligations related to the remaining buy-out options.

(c)Aspen Power has obtained representation and warranty insurance, therefore, PPL generally has no liability for its representations and warranties under the agreement except for losses suffered related to items not covered. Expiration of these indemnifications range from 18 months to 6 years from the date of the closing of the transaction, and PPL's aggregate liability for these claims will not exceed $140 million subject to certain adjustments.

(d)Pursuant to the OVEC power purchase contract, LG&E and KU are obligated to pay for their share of OVEC's excess debt service, post-retirement and decommissioning costs, as well as any shortfall from amounts included within a demand charge designed and expected to cover these costs over the term of the contract. PPL's proportionate share of OVEC's outstanding debt was $71 million at December 31, 2025, consisting of LG&E's share of $49 million and KU's share of $22 million. The maximum exposure and the expiration date of these potential obligations are not presently determinable. See "Energy Purchase Commitments" above for additional information on the OVEC power purchase contract.

The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business. These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration. The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is remote.

PPL, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage. The coverage provides maximum aggregate coverage of $231 million for non-wildfire liability losses and maximum aggregate coverage of $181 million for wildfire liability losses. This insurance may be applicable to obligations under certain of these contractual arrangements.

PPL Corp 10-K