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Utility Rate Regulation
 12 Months Ended
Dec. 31, 2023
Utility Rate Regulation [Line Items]  
Utility Rate Regulation
7. Utility Rate Regulation

Regulatory Assets and Liabilities

(All Registrants)

PPL, PPL Electric, LG&E and KU reflect the effects of regulatory actions in the financial statements for their rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to an item will be recovered or refunded within a year of the balance sheet date.

(PPL)

RIE is subject to the jurisdiction of the RIPUC, the Rhode Island Division of Public Utilities and Carriers, and the FERC. RIE operates under a FERC-approved open access transmission tariff. RIE's base distribution rates are calculated based on recovery of costs as well as a return on rate base. Certain other recovery mechanisms exist to recover expenses and capital investments with a return on rate base separate from the base distribution rate case process.
(PPL, LG&E and KU)

LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the FERC and the VSCC.

LG&E's and KU's Kentucky base rates are calculated based on recovery of costs as well as a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets.

(PPL and KU)

KU's Virginia base rates are calculated based on recovery of costs as well as a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except for regulatory assets and liabilities related to the levelized fuel factor, accumulated deferred income taxes, pension and postretirement benefits, and AROs related to certain CCR impoundments, are excluded from the return on rate base utilized in the calculation of Virginia base rates, no return is earned on the related assets.

KU's rates to municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets.

(PPL and PPL Electric)

PPL Electric is subject to the jurisdiction of the PAPUC and the FERC. PPL Electric's distribution base rates are calculated based on recovery of costs as well as a return on distribution rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions) and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(All Registrants)

The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations at December 31:
 PPLPPL ElectricLG&EKU
 20232022202320222023202220232022
Current Regulatory Assets:    
Gas supply clause$— $41 $— $— $— $13 $— $— 
Rate adjustment mechanism118 96 — — — — — — 
Renewable energy certificates14 14 — — — — — — 
Derivative Instruments51 41 — — — — — — 
Smart meter rider6 5 6 5 — — — — 
Storm damage expense12 — 12 — — — — — 
Universal service rider— 3 — 3 — — — — 
Fuel adjustment clause4 38 — — 3 9 — 29 
Transmission service charge43 — 31 — — — — — 
DSIC7 5 7 5 — — — — 
Other38 15 1 — 4 1 3 3 
Total current regulatory assets $293 $258 $57 $13 $7 $23 $3 $32 
Noncurrent Regulatory Assets:   
Defined benefit plans $887 $778 $417 $353 $217 $209 $136 $140 
Plant outage cost38 46 — — 10 12 28 34 
Net Metering112 61 — — — — — — 
Environmental Cost recovery99 102 — — — — — — 
Taxes recoverable through future rates— 47 — — — — — — 
Storm costs97 118 — — 15 7 14 3 
Unamortized loss on debt22 21 3 3 10 11 7 7 
Interest rate swaps7 7 — — 7 7 — — 
Terminated interest rate swaps58 63 — — 34 37 24 26 
Accumulated cost of removal of utility plant178 212 178 212 — — — — 
AROs289 295 — — 76 76 213 219 
Derivative Instruments8 — — — — — — — 
Other79 69 — — 26 14 17 13 
Total noncurrent regulatory assets$1,874 $1,819 $598 $568 $395 $373 $439 $442 
PPLPPL ElectricLG&EKU
20232022202320222023202220232022
Current Regulatory Liabilities:
Generation supply charge$51 $37 $51 $37 $— $— $— $— 
Transmission service charge— 14 — 7 — — — — 
TCJA customer refund5 15 5 15 — — — — 
Act 129 compliance rider15 14 15 14 — — — — 
Transmission formula rate21 12 18 12 — — — — 
Rate adjustment mechanism72 96 — — — — — — 
Energy efficiency23 23 — — — — — — 
Gas supply clause15 — — — 15 — — — 
Other23 27 2 — 1 7 1 6 
Total current regulatory liabilities
$225 $238 $91 $85 $16 $7 $1 $6 
Noncurrent Regulatory Liabilities:    
Accumulated cost of removal of utility plant$996 $950 $— $— $306 $287 $399 $389 
Power purchase agreement - OVEC19 26 — — 13 18 6 8 
Net deferred taxes1,977 2,094 763 775 459 477 523 546 
Defined benefit plans252 187 73 45 20 21 59 56 
Terminated interest rate swaps57 60 — — 29 30 28 30 
Energy efficiency5 32 — — — — — — 
Other34 63 — — — — 3 — 
Total noncurrent regulatory liabilities$3,340 $3,412 $836 $820 $827 $833 $1,018 $1,029 

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."
Defined Benefit Plans

(All Registrants)

Defined benefit plan regulatory assets and liabilities represent prior service cost and net actuarial gains and losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices and, generally, are amortized over the average remaining service lives of plan participants. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is remeasured.

(PPL, LG&E and KU)

As a result of previous rate case settlements and orders, the difference between pension cost calculated in accordance with LG&E's and KU's pension accounting policy and pension cost calculated using a 15-year amortization period for actuarial gains and losses and settlements are recorded as a regulatory asset. As of December 31, 2023, the balances were $86 million for PPL, $46 million for LG&E and $40 million for KU. As of December 31, 2022, the balances were $107 million for PPL, $57 million for LG&E and $50 million for KU.

(PPL)

RIE is subject to a pension rate adjustment mechanism whereby the difference in amounts allowed to be recovered in rates versus actual costs of RIE’s pension and other postretirement benefit plans that are to be recovered from or passed back to customers in future periods, are also recorded as regulatory assets and liabilities.

(All Registrants)

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PAPUC, the KPSC and the VSCC, as applicable, the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once such authority is granted, LG&E and KU can request recovery of those expenses in a base rate case and begin amortizing the costs when recovery starts. PPL Electric can recover qualifying expenses caused by major storm events, as defined in its retail tariff, over three years through the Storm Damage Expense Rider commencing in the application year after the storm occurred. LG&E's and KU's regulatory assets for storm costs approved for base rate recovery are being amortized through various dates ending in 2031.

As provided in the ASA, RIE has the authority from the RIPUC to treat certain incremental O&M expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once all expenses for the extraordinary storm have been finalized, RIE files a final accounting of those storm expenses with the RIPUC that is subject to review by the RIPUC and the Rhode Island Division of Public Utilities and Carriers.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt refinanced, reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2053 for PPL Electric, through 2042 for KU, and through 2044 for LG&E.

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.

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 is included in rates and amortized over the subsequent five-year period.
Net Deferred Taxes

Regulatory liabilities associated with net deferred taxes represent the future revenue impact from the adjustment of deferred income taxes required primarily for excess deferred taxes and unamortized investment tax credits, largely a result of the TCJA enacted in 2017.

(PPL and PPL Electric)

Distribution System Improvement Charge (DSIC)

The DSIC is authorized under Act 11 and is considered an alternative ratemaking mechanism providing more timely cost recovery of qualifying distribution system capital improvements. DSIC is charged to all customers taking distribution service as a percentage of total distribution revenue (excluding State Tax Adjustment Surcharge). DSIC is capped at 5% of the total amount billed to all customers for distribution service (including reconcilable riders) which provides a safeguard for customers. PPL Electric is permitted to utilize the DSIC mechanism so long as the rolling 12 month ROE for the applicable period does not exceed the PUC ROE in the company’s PAPUC quarterly financial report filing. The DSIC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

Generation Supply Charge (GSC)

The GSC is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service. The recovery includes charges for generation supply, as well as administration of the acquisition process. In addition, the GSC contains a reconciliation mechanism whereby any over- or under-recovery from prior periods is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent rate filing period.

Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PAPUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

RIE arranges transmission service on behalf of its customers and bills the costs of those services to customers, pursuant to its Transmission Service Cost Adjustment Provision. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

Transmission Formula Rate

PPL Electric's transmission revenues are billed in accordance with a FERC-approved Open Access Transmission Tariff that utilizes a formula-based rate recovery mechanism. Under this formula, beginning in 2023, rates are put into effect on January 1st of each year based upon actual expenditures from the most recently filed FERC Form 1, forecasted capital additions, and other data based on PPL Electric’s books and records. 2023 is considered a transitional period as the calendar year rate approved by FERC became effective April 1, 2023. Rates are compared during the year to the estimated annual expenses and capital additions that will be filed in PPL Electric’s annual FERC Form 1, filed under the FERC's Uniform System of Accounts. Under the mechanism, any difference between the revenue requirement in effect and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability, and the regulatory asset or regulatory liability is to be recovered from or returned to customers starting one year after the conclusion of the rate year.

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. In the 2015 rate case settlement approved by the PAPUC in November 2015, it was determined that reportable storm damage expenses to be recovered annually through base rates will be set at $20 million. The SDER will recover from or refund to customers the applicable expenses from reportable storms as compared to the $20 million recovered annually through base rates.
Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric is currently in Phase IV of the energy efficiency and conservation plan which was approved in March 2021. Phase IV allows PPL Electric to recover the maximum $313 million over the five-year period, June 1, 2021 through May 31, 2026. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual Phase IV program costs are reconcilable after each 12-month period, and any over- or under-recovery from customers will be refunded or recovered over the next rate filing period.

Smart Meter Rider (SMR)

Act 129 requires each electric distribution company (EDC) with more than 100,000 customers to have a PAPUC approved Smart Meter Technology Procurement and Installation Plan (SMP). As of December 31, 2019, PPL Electric replaced substantially all of its old meters with meters that meet the Act 129 requirements under its SMP. In accordance with Act 129, EDCs are able to recover the costs and earn a return on capital of providing smart metering technology. PPL Electric uses the SMR to recover the costs to implement its SMP. The SMR is a reconciliation mechanism whereby any over- or under-recovery from prior years is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarters.

Universal Service Rider (USR)

The USR provides for recovery of costs associated with universal service programs, OnTrack and Winter Relief Assistance Program (WRAP), provided by PPL Electric to residential customers. OnTrack is a special payment program for low-income households and WRAP provides low-income customers a means to reduce electric bills through energy saving methods. The USR rate is applied to residential customers who receive distribution service. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.

TCJA Customer Refund

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. Timing differences between the recognition of these tax benefits and the refund of the benefit to the customer creates a regulatory liability. PPL Electric's liability is being credited back to distribution customers through a temporary negative surcharge and remains in place until PPL Electric files and the PAPUC approves new base rates. The TCJA is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.

(PPL, LG&E and KU)

Fuel Adjustment Clauses

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in power purchases and the cost of fuel to generate electricity, including transportation costs, from the costs embedded in base rates are adjusted in LG&E's and KU's rates. The KPSC requires formal reviews at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel adjustment clause and, to the extent appropriate, may conduct public hearings and reestablish the fuel charge included in base rates. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered within 12 months.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs and load for the fuel year (12 months ending March 31). The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the fuel year plus an adjustment for any under- or over-recovery of fuel expenses from the prior fuel year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered or refunded within 12 months.

AROs

As discussed in Note 1, for LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal.
Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LG&E and KU, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LG&E and KU with offsets to regulatory liabilities. The regulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition. LG&E's and KU's customer rates continue to reflect the original contracts. See Notes 13 and 18 for additional discussion of the power purchase agreement.

Interest Rate Swaps

LG&E's unrealized gains and losses are recorded as regulatory assets or regulatory liabilities until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures in 2033.

Terminated Interest Rate Swaps

Net realized gains and losses on all interest rate swaps are recovered through regulated rates. As such, any gains and losses on these derivatives are included in regulatory assets or liabilities and are primarily recognized in "Interest Expense" on the Statements of Income over the life of the associated debt.

Plant Outage Costs

From July 1, 2017 through June 30, 2021, plant outage costs were normalized for ratemaking purposes based on an average level of expenses. Plant outage expenses that were greater or less than the average will be collected from or returned to customers, through future base rates. Effective July 1, 2021 under-recovered plant outage costs are being amortized through 2029 for LG&E and KU.

(PPL)

Derivative Instruments

RIE evaluates open derivative instruments for regulatory deferral by determining if they are probable of recovery from, or refund to, customers through future rates. Derivative instruments that qualify for recovery are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. The balance is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.

Energy Efficiency

Energy efficiency represents the difference between revenue billed to customers through RIE's energy efficiency charge and the costs of the RIE’s energy efficiency programs as approved by the RIPUC.

The energy efficiency charge is designed to collect the estimated costs of the RIE’s energy efficiency plan for the upcoming calendar year. The final annual over/under is reconciled in the next year's energy efficiency plan filing, as part of the reconciliation factor calculation. RIE may file to change the energy efficiency plan charge at any time should significant over-or under-recoveries occur.

Net Metering

Net metering deferral reflects the recovery mechanism for costs associated with customer-installed on-site generation facilities, including the costs of renewable generation credits. This surcharge provides RIE with a mechanism to recover such amounts. Net metering is reconcilable annually, and any over- or under-recovery from customers will be refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
Rate Adjustment Mechanisms

In addition to commodity costs, RIE is subject to a number of additional rate adjustment mechanisms whereby an asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the RIPUC. The rate adjustment mechanisms are reconcilable, and any over- or under-recovery from customers are to be refunded or recovered annually in the subsequent year.

Renewable energy certificates (RECs)

Represents deferred costs associated with RIE's compliance obligation with the Rhode Island Renewable Portfolio Standard (RPS). The RPS is legislation established to foster the development of new renewable energy sources. The regulatory asset will be recovered over the next year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that are anticipated to be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

(PPL, LG&E and KU)

Environmental Cost Recovery

Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Clean Air Act and those federal, state or local environmental requirements, which apply to coal combustion wastes and by-products from coal-fired electricity generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The KPSC has authorized return on equity of 9.35% for existing approved ECR projects. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is typically recovered or refunded within 12 months.

RIE's rate plans provide for specific rate allowances for RIE's share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated, with variances deferred for future recovery from, or return to, customers. RIE believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. The regulatory asset represents the excess of amounts incurred for RIE's actual site investigation and remediation costs versus amounts received in rates.

(PPL and LG&E)

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs and customer usage from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause also includes a separate natural gas procurement incentive mechanism, which allows LG&E's rates to be adjusted annually to share savings between the actual cost of gas purchases and market indices, with the shareholders and the customers during each performance-based rate year (12 months ending October 31). The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are typically recovered or refunded within 18 months.
Regulatory Matters

Rhode Island Activities (PPL)

Rate Case proceedings

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 on track for timely completion, (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 has paused the ET programs in Rate Year 5.

Advanced Metering Functionality (AMF)

In 2021, RIE filed its Updated AMF Business Case and Grid Modernization Plan (GMP) with the RIPUC in accordance with the Amended Settlement Agreement (ASA) approved by the RIPUC in August 2018, and which among other things, sought approval to deploy smart meters throughout the service territory. After PPL completed the acquisition of RIE, RIE filed a new AMF Business Case with the RIPUC in 2022, consisting of a detailed proposal for full-scale deployment of AMF across its electric service territory.

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.

Grid Modernization

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 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.

Petition for Deferral of Credit Card Fees

On January 31, 2024, RIE filed a petition to request approval to recognize regulatory assets related to the credit card, debit card, and related fees (Electronic Transaction Fees) that RIE has waived and will continue to waive on a going forward basis
pursuant to the RIPUC orders in RIPUC Docket No. 5022 related to COVID-19 impacts. If approved, RIE plans to include a proposal as part of its next base distribution rate case for the amortization/recovery of the regulatory assets and to include future Electronic Transaction Fees in base distribution rates. RIE simultaneously filed a Notice of Withdrawal of its April 2021 petition to create regulatory assets for COVID-19 related bad debt expense and the lost revenue from unassessed late payment charges pending in Docket No. 5154. RIE is continuing to evaluate these other COVID-19 related costs and intends to reserve its rights to file for recovery of these costs in the future. RIE cannot predict the outcome of this matter.

FY 2023 Gas Infrastructure, Safety and Reliability (ISR) Plan

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. The RIPUC held an Open Meeting on September 13, 2022, and issued its Order on November 18. 2022 regarding the Proactive Main Replacement Program and made the following rulings: (i) commencing with the Gas ISR plan to be filed in this calendar year 2022 (prospectively), new main constructed to replace leak prone pipe will not be considered used and useful, and therefore not eligible for rate base treatment, until the related old main is abandoned; and (ii) approved the proactive main replacement revenue requirement set forth in the FY 2023 Gas ISR plan. Also, the RIPUC directed RIE to submit prefiled testimony on the issue of its replacement of heating and pressure regulation facilities at the Wampanoag and Tiverton take stations and to address three issues, specifically: (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. RIE filed this testimony with the RIPUC on May 16, 2022, and the RIPUC has not taken any action to date on this issue. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan process. A new docket has been opened to address this matter with the goal of implementing changes for the FY 2025 ISR Plan. RIE filed its proposed gas ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan filing on December 22, 2023. RIE cannot predict the outcome of these matters.

FY 2024 Gas ISR Plan

On December 23, 2022, RIE filed its FY 2024 Gas ISR Plan with the RIPUC. At its January 20, 2023 Open Meeting, the RIPUC directed RIE to file supplemental budget and rate schedules to reflect an April 1 to March 31 fiscal year. The supplemental budget that was filed with the RIPUC on January 27, 2023 includes $187 million of capital investment spend. The supplemental rate schedules were filed on February 3, 2023. RIE and the Rhode Island Division of Public Utilities and Carriers reached an agreement on an approximately $171 million capital investment spending plan, and RIE filed a second supplemental budget on March 13, 2023. The RIPUC held a hearing on the plan on March 14, 2023. At an Open Meeting on March 29, 2023, the RIPUC approved the 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. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan review and approval process starting with the FY 2025 ISR Plan. A new docket has been opened to address this matter with the goal of implementing changes for the FY 2025 ISR Plan. RIE filed its proposed gas ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan filing on December 22, 2023. RIE cannot predict the outcome of these matters.

FY 2025 Gas ISR Plan

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 and up to $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 would significantly alter RIE’s leak detection and repair obligations under federal regulations. RIE also filed its proposed gas ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan. The RIPUC has scheduled hearings on March 7 and 11, 2024, and is scheduled to rule on the plan by the end of March 2024. RIE cannot predict the outcome of these matters.
FY 2024 Electric ISR Plan

On December 23, 2022, RIE filed its FY 2024 Electric ISR Plan with the RIPUC. At its January 20, 2023 Open Meeting, the RIPUC directed RIE to file supplemental budget and rate schedules to reflect an April 1 to March 31 fiscal year. The supplemental budget filed with the RIPUC on January 27, 2023 includes $176 million of capital investment spend, $14 million of vegetation operations and management (O&M) spend and $3 million of Other O&M spend. The supplemental rate schedules were filed on February 3, 2023. RIE filed second supplemental budget schedules on March 21, 2023 which includes $166 million of capital investment spend, $14 million of vegetation management O&M spend and $1 million of Other O&M spend. The RIPUC held hearings in March 2023, and on March 29, 2023, approved the plan with modifications to the proposed capital investment spend, resulting in a total approved FY 2024 Electric ISR Plan of $112 million for capital investment spend, $14 million for vegetation management O&M spend, and $1 million for Other O&M spend.

On March 31, 2023, the RIPUC approved RIE's March 30, 2023 compliance filing for rates effective April 1, 2023. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan review and approval process. A new docket has been opened to address this matter with the goal of implementing changes for the FY 2025 ISR Plan. RIE filed its proposed electric ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan filing on December 21, 2023. RIE cannot predict the outcome of these matters.

FY 2025 Electric ISR Plan

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 with its FY 2025 ISR Plan. The RIPUC has scheduled hearings on March 13 and 14, 2024, and is scheduled to rule on the plan by the end of March 2024. RIE cannot predict the outcome of these matters.

Kentucky Activities (PPL, LG&E and KU)

CPCN and SB 4 Application

On December 15, 2022, LG&E and KU filed an application with the KPSC for a CPCN for the construction and purchase of various generating facilities in conjunction with the retirement of four existing coal-fired generation units and three small gas-fired units. On March 24, 2023, Kentucky Senate Bill 4 (SB 4) went into effect, which requires KPSC approval of the retirement of fossil fuel-fired electric generating units in the state. On May 10, 2023, LG&E and KU filed an application with the KPSC seeking approval of the retirement of seven fossil fuel-fired generating units as required by SB 4. On May 16, 2023, the KPSC entered an Order consolidating the SB 4 filing proceeding into the CPCN case.

On November 6, 2023, the KPSC issued an order approving LG&E’s and KU’s requests (i) to construct a 640 MW net summer rating NGCC combustion turbine at LG&E's Mill Creek Generating Station in Jefferson County, Kentucky, (ii) to construct a 120 MWac solar photovoltaic electric generating facility in Mercer County, Kentucky, (iii) to acquire a 120 MWac solar facility to be built by a third-party solar developer in Marion County, Kentucky and (iv) to construct a 125 MW, 4-hour battery energy storage system facility at KU's E.W. Brown Generating Station. The KPSC denied the request to construct a 621 MW net summer rating NGCC combustion turbine at KU's E.W. Brown Generating Station in Mercer County, Kentucky at this time, based on the finding that the construction of this unit should be deferred with the construction date beginning on a date that provides for an in-service date in 2030. The order also authorized LG&E's and KU's entry into the four solar PPAs, subject to certain conditions, but deferred for future proceedings specific decisions on cost recovery treatment or mechanisms. Further, the order approved the new, adjusted or expanded energy efficiency programs contained in the requested 2024-2030 DSM plan.

The KPSC order included approval of the requested retirements of two existing coal-fired generation units at LG&E's Mill Creek Unit 1 (300 MW) and 2 (297 MW) in 2024 and 2027, subject to certain conditions, and three small gas-fired units. The order denied approval of the retirement of KU's E.W. Brown 3 Unit (412 MW) and Ghent Unit 2 (486 MW) in 2028 at this time, citing the need for additional clarity regarding environmental compliance regulations.

The new NGCC facility will be jointly owned by LG&E (31%) and KU (69%) and the solar units will be jointly owned by LG&E (37%) and KU (63%), the battery storage unit will be owned by LG&E, and the proposed PPA transactions and DSM programs will be entered into or conducted jointly by LG&E and KU, consistent with LG&E and KU's shared dispatch, cost allocation, tariff or other frameworks.
The order approved the requested AFUDC accounting treatment for associated financing costs, each as relating to the NGCC, solar and battery facilities to be constructed and owned by LG&E and KU. With respect to generating unit retirements that were approved by the KPSC, and separate from the order, LG&E and KU anticipate the recovery of associated costs, including the remaining net book value, for these units through the RAR or other rate mechanisms. The remaining net book values of LG&E’s Mill Creek 1 and 2 generating units were approximately $95 million and $244 million at December 31, 2023 and LG&E is continuing to depreciate these units using the current approved rates through their retirement dates in 2024 and 2027. LG&E expects to reclassify the net book value remaining at retirement, which is expected to total approximately $83 million for Mill Creek Unit 1 and $160 million for Mill Creek Unit 2, to a regulatory asset to be amortized over a period of ten years in accordance with the RAR.

Kentucky March 2023 Storm

On March 3, 2023, 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 costs incurred through December 31, 2023 of $74 million ($33 million at LG&E and $41 million at KU). On March 17, 2023, 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 windstorm. On April 5, 2023, the KPSC issued an order approving the request for accounting purposes, noting that approval for recovery would be determined in LG&E’s and KU’s next base rate cases. As of December 31, 2023, LG&E and KU recorded regulatory assets related to the storm of $8 million and $11 million.

KPSC Investigation Related to Winter Storm Elliott

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 have been granted intervenor status for the proceeding and discovery is currently scheduled to continue through March 15, 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.

Pennsylvania Activities (PPL and PPL Electric)

PAPUC investigation into billing issues

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 agree to not seek recovery for extraordinary costs incurred in responding to 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 Commission entering a Final Order on the petition. Comments are due on February 28, 2024. PPL Electric is waiting for the PAPUC to issue a Final Order on the Joint Petition for Approval of Settlement. Approval is pending until the Commission has provided its final decision. PPL Electric cannot predict the outcome of this matter.
Act 129
 
Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet, by specified dates, specified goals for reduction in customer electricity usage and peak demand. EDCs not meeting the requirements of Act 129 are subject to significant penalties. PPL Electric filed with the PAPUC its Act 129 Phase IV Energy Efficiency and Conservation Plan on November 30, 2020, for the five-year period starting June 1, 2021 and ending on May 31, 2026. PPL Electric's Phase IV Act 129 Plan was approved by the PAPUC at its March 25, 2021, public meeting.

Act 129 also requires EDCs to act as a default service provider (DSP), which provides electricity generation supply service to customers pursuant to a PAPUC-approved default service procurement plan. A DSP is able to recover the costs associated with its default service procurement plan.

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 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 and KU’s compliance filing on November 16, 2023, and LG&E and KU filed a petition for review of this November 16 order on February 14, 2024. The proceedings at the D.C. Circuit Court of Appeals were held on abeyance until February 15, 2024, but a motion to hold the proceedings on abeyance for an additional 60 days was filed on February 15, 2024, to allow the FERC time to substantively address LG&E and KU’s request for rehearing of the November 16 order. 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'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 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 a PAPUC-approved purchase of accounts receivable program, PPL Electric purchases 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 2023, 2022 and 2021, PPL Electric purchased $1.5 billion, $1.3 billion and $1.2 billion of accounts receivable from alternative suppliers.

(PPL)

In 2021 and 2022, the RIPUC approved various components of a Purchase of Receivables Program (POR) in Rhode Island for effect on April 1, 2022. Municipal aggregators and non-regulated power producers (collectively, Competitive Suppliers) are eligible to participate in accordance with RIE's approved electric tariffs for municipal aggregation and non-regulated power producers. Under the POR program, RIE will purchase the Competitive Suppliers' accounts receivables, including existing receivables, at discounted rates, regardless of whether RIE has collected the owed monies from customers. The program is intended to make RIE whole through the implementation of a discount rate or Standard Complete Bill Percentage (SCBP) paid by Competitive Suppliers. RIE calculates the SCBP for each customer class and files the calculations with the RIPUC for review and approval by February 15 of each year. At an Open Meeting on March 29, 2023, the RIPUC approved the SCBP for effect beginning on April 1, 2023 for a one-year period.