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Utility Rate Regulation | 12 Months Ended
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Dec. 31, 2018
Utility Rate Regulation [Line Items] |
Utility Rate Regulation | Regulatory Assets and Liabilities (All Registrants) PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based 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) WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities. See Note 1 for additional information. (PPL, LKE, LG&E and KU) LG&E is subject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC and VSCC. LG&E's and KU's Kentucky base rates are calculated based on 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. As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of power purchases. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at LKE's acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate-making impact of the fair value adjustments. LG&E's and KU's customer rates continue to reflect the original contracted prices for remaining contracts. (PPL, LKE and KU) KU's Virginia base rates are calculated based on 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 the levelized fuel factor and regulatory assets or liabilities recorded for 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 10 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 regulatory assets recorded for AROs related to certain CCR impoundments, 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'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:
| PPL |  | PPL Electric
| 2018 |  | 2017 |  | 2018 |  | 2017
Current Regulatory Assets: |  |  |  |  |  |  |
Environmental cost recovery | $ | — |  |  | $ | 5 |  |  | $ | — |  |  | $ | — |
Generation formula rate | — |  |  | 6 |  |  | — |  |  | — |
Gas supply clause | 12 |  |  | 4 |  |  | — |  |  | — |
Smart meter rider | 11 |  |  | 15 |  |  | 11 |  |  | 15 |
Plant outage costs | 10 |  |  | 3 |  |  | — |  |  | — |
Other | 3 |  |  | 1 |  |  | — |  |  | 1 |
Total current regulatory assets (a) | $ | 36 |  |  | $ | 34 |  |  | $ | 11 |  |  | $ | 16 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |
Defined benefit plans | $ | 963 |  |  | $ | 880 |  |  | $ | 558 |  |  | $ | 504 |
Taxes recoverable through future rates | 3 |  |  | 3 |  |  | 3 |  |  | 3 |
Storm costs | 56 |  |  | 33 |  |  | 22 |  |  | — |
Unamortized loss on debt | 45 |  |  | 54 |  |  | 22 |  |  | 29 |
Interest rate swaps | 20 |  |  | 26 |  |  | — |  |  | — |
Terminated interest rate swaps | 87 |  |  | 92 |  |  | — |  |  | — |
Accumulated cost of removal of utility plant | 200 |  |  | 173 |  |  | 200 |  |  | 173 |
AROs | 273 |  |  | 234 |  |  | — |  |  | — |
Act 129 compliance rider | 19 |  |  | — |  |  | 19 |  |  | — |
Other | 7 |  |  | 9 |  |  | — |  |  | — |
Total noncurrent regulatory assets | $ | 1,673 |  |  | $ | 1,504 |  |  | $ | 824 |  |  | $ | 709 |
Current Regulatory Liabilities: |  |  |  |  |  |  |
Generation supply charge | $ | 33 |  |  | $ | 34 |  |  | $ | 33 |  |  | $ | 34 |
Transmission service charge | 3 |  |  | 9 |  |  | 3 |  |  | 9 |
Environmental cost recovery | 16 |  |  | 1 |  |  | — |  |  | — |
Universal service rider | 27 |  |  | 26 |  |  | 27 |  |  | 26 |
Transmission formula rate | 3 |  |  | 9 |  |  | 3 |  |  | 9 |
TCJA customer refund | 20 |  |  | — |  |  | 3 |  |  | — |
Storm damage expense rider | 5 |  |  | 8 |  |  | 5 |  |  | 8 |
Other | 15 |  |  | 8 |  |  | — |  |  | — |
Total current regulatory liabilities | $ | 122 |  |  | $ | 95 |  |  | $ | 74 |  |  | $ | 86 |
| PPL |  | PPL Electric
| 2018 |  | 2017 |  | 2018 |  | 2017
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 674 |  |  | $ | 677 |  |  | $ | — |  |  | $ | — |
Power purchase agreement - OVEC | 59 |  |  | 68 |  |  | — |  |  | — |
Net deferred taxes | 1,826 |  |  | 1,853 |  |  | 629 |  |  | 668 |
Defined benefit plans | 37 |  |  | 27 |  |  | 5 |  |  | — |
Terminated interest rate swaps | 72 |  |  | 74 |  |  | — |  |  | — |
TCJA customer refund | 41 |  |  | — |  |  | 41 |  |  | — |
Other | 5 |  |  | 5 |  |  | — |  |  | — |
Total noncurrent regulatory liabilities | $ | 2,714 |  |  | $ | 2,704 |  |  | $ | 675 |  |  | $ | 668 |
| LKE |  | LG&E |  | KU
| 2018 |  | 2017 |  | 2018 |  | 2017 |  | 2018 |  | 2017
Current Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |
Plant outage costs | $ | 10 |  |  | $ | 3 |  |  | $ | 7 |  |  | $ | 3 |  |  | $ | 3 |  |  | $ | — |
Generation formula rate | — |  |  | 6 |  |  | — |  |  | — |  |  | — |  |  | 6 |
Gas supply clause | 12 |  |  | 4 |  |  | 12 |  |  | 4 |  |  | — |  |  | — |
Other | 3 |  |  | 5 |  |  | 2 |  |  | 5 |  |  | 1 |  |  | — |
Total current regulatory assets | $ | 25 |  |  | $ | 18 |  |  | $ | 21 |  |  | $ | 12 |  |  | $ | 4 |  |  | $ | 6 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |
Defined benefit plans | $ | 405 |  |  | $ | 376 |  |  | $ | 249 |  |  | $ | 234 |  |  | $ | 156 |  |  | $ | 142 |
Storm costs | 34 |  |  | 33 |  |  | 20 |  |  | 18 |  |  | 14 |  |  | 15 |
Unamortized loss on debt | 23 |  |  | 25 |  |  | 15 |  |  | 16 |  |  | 8 |  |  | 9 |
Interest rate swaps | 20 |  |  | 26 |  |  | 20 |  |  | 26 |  |  | — |  |  | — |
Terminated interest rate swaps | 87 |  |  | 92 |  |  | 51 |  |  | 54 |  |  | 36 |  |  | 38 |
AROs | 273 |  |  | 234 |  |  | 75 |  |  | 61 |  |  | 198 |  |  | 173 |
Other | 7 |  |  | 9 |  |  | 1 |  |  | 2 |  |  | 6 |  |  | 7 |
Total noncurrent regulatory assets | $ | 849 |  |  | $ | 795 |  |  | $ | 431 |  |  | $ | 411 |  |  | $ | 418 |  |  | $ | 384 |
Current Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |
Environmental cost recovery | $ | 16 |  |  | $ | 1 |  |  | $ | 6 |  |  | $ | — |  |  | $ | 10 |  |  | $ | 1 |
Fuel adjustment clauses | — |  |  | 3 |  |  | — |  |  | — |  |  | — |  |  | 3 |
Gas line tracker | 2 |  |  | 3 |  |  | 2 |  |  | 3 |  |  | — |  |  | — |
TCJA customer refund | 17 |  |  | — |  |  | 7 |  |  | — |  |  | 10 |  |  | — |
Generation formula Rate | 7 |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | — |
Other | 6 |  |  | 2 |  |  | 2 |  |  | — |  |  | 4 |  |  | 2 |
Total current regulatory liabilities | $ | 48 |  |  | $ | 9 |  |  | $ | 17 |  |  | $ | 3 |  |  | $ | 31 |  |  | $ | 6 |
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 674 |  |  | $ | 677 |  |  | $ | 279 |  |  | $ | 282 |  |  | $ | 395 |  |  | $ | 395 |
Power purchase agreement - OVEC | 59 |  |  | 68 |  |  | 41 |  |  | 47 |  |  | 18 |  |  | 21 |
Net deferred taxes | 1,197 |  |  | 1,185 |  |  | 557 |  |  | 552 |  |  | 640 |  |  | 633 |
Defined benefit plans | 32 |  |  | 27 |  |  | — |  |  | — |  |  | 32 |  |  | 27 |
Terminated interest rate swaps | 72 |  |  | 74 |  |  | 36 |  |  | 37 |  |  | 36 |  |  | 37 |
Other | 5 |  |  | 5 |  |  | 2 |  |  | 1 |  |  | 3 |  |  | 4 |
Total noncurrent regulatory liabilities | $ | 2,039 |  |  | $ | 2,036 |  |  | $ | 915 |  |  | $ | 919 |  |  | $ | 1,124 |  |  | $ | 1,117 |
(a) | For PPL, these amounts are included in "Other current assets" on the Balance Sheets.
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. Effective January 1, 2018, the Registrants adopted new accounting guidance that changes the income statement presentation of net periodic benefit cost and limits the capitalization to the service cost component of net periodic benefit cost. The non-service costs or credits that would have been capitalized under previous guidance are still able to be recovered through future base rates and are therefore now recognized as a regulatory asset or liability and amortized over the weighted average useful life of the asset base on which those non-service costs would have been capitalized. As of December 31, 2018, the regulatory liability balances were $11 million for PPL, $5 million for PPL Electric and $6 million for LKE and KU. As of December 31, 2018, the regulatory asset balances were $1 million for PPL, LKE and LG&E. (PPL, LKE, LG&E and KU) As a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, 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 is recorded as a regulatory asset. As of December 31, 2018, the balances were $45 million for PPL and LKE, $25 million for LG&E and $20 million for KU. As of December 31, 2017, the balances were $33 million for PPL and LKE, $18 million for LG&E and $15 million for KU. (All Registrants) Storm Costs PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and 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. PPL Electric's regulatory assets for storm costs are being amortized through various dates ending in 2021. The amortization period of LG&E's and KU's regulatory assets for storm costs are subject to the results of the current Kentucky rate case discussed below in "Regulatory Matters - Kentucky Activities - Rate Case Proceedings." Unamortized Loss on Debt Unamortized loss on reacquired debt represents losses on long-term debt 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 2029 for PPL Electric, through 2042 for KU, and through 2044 for LKE and LG&E. Accumulated Cost of Removal of Utility Plant 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. TCJA Customer Refund As a result of the reduced U.S. federal corporate income tax rate as enacted by the TCJA, the regulators of PPL Electric, LG&E and KU have ruled that these tax benefits should be refunded to customers. In some instances, timing differences occur between the recognition of these tax benefits and the refund of the benefit to the customers which create a regulatory asset or liability. LG&E and KU are currently distributing these amounts through the TCJA bill credit until tax-related savings will be reflected in base rates. PPL Electric's current liability relates to the period of July 1, 2018 through December 31, 2018 and will be credited back to distribution customers through a negative surcharge which became effective July 1, 2018. Additionally, PPL Electric's noncurrent liability balance relates to the period of January 1, 2018 through June 30, 2018 which is not yet reflected in distribution customer rates. PPL Electric must propose to the PUC the method by which it would like to return the amount of this liability to customers at the earlier of May 2021 or PPL Electric's next rate case. 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. See Note 6 for additional information on the TCJA. (PPL and PPL Electric) 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 quarters 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 PUC-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. 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, rates are put into effect in June of each year based upon prior year actual expenditures and current year forecasted capital additions. Rates are then adjusted the following year to reflect actual annual expenses and capital additions, as reported in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts. Any difference between the revenue requirement in effect for the prior year and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability. 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 PUC 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, as appropriate, only applicable expenses from reportable storms that are greater than or less than $20 million recovered annually through base rates. Storm costs incurred in PPL Electric's territory from a March 2018 storm will be amortized from 2019 through 2021. Taxes Recoverable through Future Rates Taxes recoverable through future rates represent the portion of future income taxes that will 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. Act 129 Compliance Rider In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric is currently in Phase III of the energy efficiency and conservation plan which was approved in June 2016. Phase III allows PPL Electric to recover the maximum $313 million over the five year period, June 1, 2016 through May 31, 2021. 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 III 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 PUC approved Smart Meter Technology Procurement and Installation Plan (SMP). Under its SMP, PPL Electric will replace its current meters with new meters that meet the Act 129 requirements by the end of 2019. Under Act 129, EDCs are able to recover the costs and earn a return on capital of providing smart metering technology. PPL Electric uses a mechanism known as the Smart Meter Rider (SMR) to recover the costs to implement its SMP on a full and current basis. 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. (PPL, LKE, 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 a return on equity of 9.7% for all existing approved ECR plans and 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 within 12 months. Fuel Adjustment Clauses LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in 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 public hearings 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, 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. LG&E's fuel adjustment clause asset is included within other current regulatory assets above. KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior 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 within 12 months. AROs As discussed in Note 1, for LKE, LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, at the time of retirement, the related ARO regulatory asset is offset against the associated cost of removal regulatory liability, PP&E and ARO liability. Power Purchase Agreement - OVEC As a result of purchase accounting associated with PPL's acquisition of LKE, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LKE, 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. See Notes 1, 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 through 2033. Terminated Interest Rate Swaps Net realized gains and losses on all interest rate swaps are probable of recovery 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 The Stipulation to the 2016 Kentucky rate case that became effective July 1, 2017 provided for the normalization of expenses associated with plant outages using an eight-year average. The eight-year average is comprised of four historical years' and four forecasted years' expenses. Plant outage expenses that are greater or less than the eight-year average will be collected from or returned to customers, through future base rates. Prior year plant outage liabilities are included within other current regulatory liabilities above. (PPL, LKE and LG&E) Gas Line Tracker The GLT authorizes LG&E to recover its incremental operating expenses, depreciation, property taxes and cost of capital, including a return on equity, for capital associated with the five year gas service riser, leak mitigation and customer service line ownership programs. As part of this program, LG&E makes necessary repairs to the gas distribution system and assumes ownership of service lines when replaced. In the 2016 rate case, the KPSC approved additional projects for recovery through the GLT mechanism related to further gas line replacements and transmission pipeline modernizations. Effective July 1, 2017, LG&E is authorized to earn a 9.7% return on equity for the GLT mechanism. As part of the 2016 rate case, LG&E now annually files a combined application which includes revised rates based on projected costs and a balancing adjustment calculation with rates effective on the first billing cycle in May. After the completion of a plan year, the balancing adjustment, as part of the combined application filing to the KPSC, amends rates charged for the differences between the actual costs and actual GLT charges for the preceding year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to these cost differences. 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 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 within 18 months. (PPL, LKE and KU) Generation Formula Rate KU provides wholesale requirements service to its municipal customers and bills for this service pursuant to a FERC approved generation formula rate. Under this formula, rates are put into effect each July utilizing a return on rate base calculation and actual expenses from the preceding year. The regulatory asset or liability represents the difference between the revenue requirement in effect for the current year and actual expenditures incurred for the current year. Regulatory Matters (PPL, LKE, LG&E and KU) Kentucky Activities Rate Case Proceedings On September 28, 2018, LG&E and KU filed requests with the KPSC for an increase in annual base electricity rates of approximately $112 million at KU and increases in annual base electricity and gas rates of approximately $35 million and $25 million at LG&E. The proposed base rate increases would result in an electricity rate increase of 6.9% at KU and electricity and gas rate increases of 3% and 7.5% at LG&E. As discussed in the "TCJA Impact on LG&E and KU Rates" section below, LG&E's and KU's applications seek to include applicable changes associated with the TCJA in the calculation of the proposed base rates and to terminate the TCJA bill credit mechanism when the new base rates go into effect. New rates are expected to become effective on May 1, 2019. The applications are based on a forecasted test year of May 1, 2019 through April 30, 2020 with a requested return-on-equity of 10.42%. A number of parties have been granted intervention requests in the proceeding. Data discovery and the filing of written testimony will continue through February 2019 and a hearing is scheduled in March 2019. LG&E and KU cannot predict the outcome of these proceedings. CPCN Filing On January 10, 2018, LG&E and KU filed an application for a CPCN with the KPSC requesting approval for implementing Advanced Metering Systems across their Kentucky service territories, including gas operations for LG&E. The application projected completion in 2021 with estimated capital costs of $166 million and $155 million for LG&E and KU. On August 30, 2018, the KPSC issued an Order denying the CPCN for full deployment of the Advanced Metering Systems. The KPSC acknowledged the benefits of Advanced Metering Systems, expanded LG&E's and KU's Advanced Metering System pilot programs and encouraged LG&E and KU to consider other items to enhance the customer experience. This decision is not expected to have a significant impact on LG&E's and KU's results of operations. TCJA Impact on LG&E and KU Rates On December 21, 2017, Kentucky Industrial Utility Customers, Inc. submitted a complaint with the KPSC against LG&E and KU, as well as other utility companies in Kentucky, alleging that their respective rates would no longer be fair, just and reasonable following the enactment of the TCJA, which reduced the federal corporate tax rate from 35% to 21%. The complaint requested the KPSC to issue an order requiring LG&E and KU to begin deferring, as of January 1, 2018, the revenue requirement effect of all income tax expense savings resulting from the federal corporate income tax reduction, including the amortization of excess deferred income taxes by recording those savings in a regulatory liability account and establishing a process by which the federal corporate income tax savings will be passed back to customers. On January 29, 2018, LG&E, KU, Kentucky Industrial Utility Customers, Inc. and the Office of the Attorney General reached a settlement agreement to commence returning savings related to the TCJA to their customers through their ECR, DSM and LG&E's GLT rate mechanisms beginning in March 2018 and through a new bill credit mechanism from April 1, 2018 through April 30, 2019 and thereafter until tax-reform related savings are reflected in changes in base rates. The estimated impact of the rate reduction represents approximately $91 million in KU electricity revenues ($70 million through the new bill credit and $21 million through existing rate mechanisms), $69 million in LG&E electricity revenues ($49 million through the new bill credit and $20 million through existing rate mechanisms) and $17 million in LG&E gas revenues (substantially all through the new bill credit) for the period January 2018 through April 2019. On March 20, 2018, the KPSC issued an Order approving, with certain modifications, the settlement agreement reached between LG&E, KU, Kentucky Industrial Utility Customers, Inc. and the Office of the Attorney General. The KPSC estimates that, pursuant to its modifications, electricity revenues would incorporate reductions of approximately $108 million for KU ($87 million through the new bill credit and $21 million through existing rate mechanisms) and $79 million for LG&E ($59 million through the new bill credit and $20 million through existing rate mechanisms). This represents $27 million ($17 million at KU and $10 million at LG&E) in additional reductions from the amounts proposed by the settlement. The KPSC's modifications to the settlement include certain changes in assumptions or inputs used in assessing tax reform or calculating LG&E's and KU's electricity rates. LG&E gas rate reductions were not modified significantly from the amount included in the settlement agreement. On September 28, 2018, the KPSC issued an Order on reconsideration, pursuant to LG&E's and KU's petition, implementing rates reflecting electricity revenue reductions of $101 million for KU ($80 million through the new bill credit and $21 million through existing rate mechanisms), $74 million for LG&E electricity revenues ($54 million through the new bill credit and $20 million through existing rate mechanisms) and $16 million LG&E gas revenues (substantially all through the new bill credit) for the period January 2018 through April 2019. This represents lower revenue reduction amounts than the March 20, 2018 Order of approximately $13 million ($7 million at KU and $6 million at LG&E). In January 2018, the VSCC ordered KU, as well as other utilities in Virginia, to accrue regulatory liabilities reflecting the Virginia jurisdictional revenue requirement impacts of the reduced federal corporate tax rate. In March 2018, KU reached a settlement agreement regarding its rate case in Virginia. New rates, inclusive of TCJA impacts, were effective June 1, 2018. The settlement also stipulates that actual tax savings for the five month period prior to new rates taking effect would be addressed through KU's annual information filing for calendar year 2018. In May 2018, the VSCC approved the settlement agreement. The TCJA and rate case are not expected to have a significant impact on KU's financial condition or results of operations related to Virginia. On November 15, 2018, the FERC issued a Policy Statement which stated that the appropriate ratemaking treatment for changes in accumulated deferred income taxes as a result of the TCJA will be addressed in a Notice of Proposed Rulemaking. Also on November 15, 2018, the FERC issued the Notice of Proposed Rulemaking which proposes that public utility transmission providers include mechanisms in their formula rates to deduct excess accumulated deferred income taxes from, or add deficient accumulated deferred income taxes to, rate base and adjust their income tax allowances by amortized excess or deficient accumulated deferred income taxes. The Notice of Proposed Rulemaking did not prescribe the mechanism companies should use to adjust their formula rates. LG&E and KU are currently assessing the Notice of Proposed Rulemaking and are continuing to monitor guidance issued by the FERC. On February 5, 2019, in connection with a separate element of federal and Kentucky state tax reform effects, LG&E and KU filed a request with the FERC to amend their transmission formula rates, effective June 1, 2019, to incorporate reductions to corporate income tax rates as a result of the TCJA and HB 487. LG&E and KU do not anticipate the impact of the TCJA related to their FERC-jurisdictional rates to be significant. (LKE and LG&E) Gas Franchise LG&E’s gas franchise agreement for the Louisville/Jefferson County service area expired in March 2016. In August 2016, LG&E and Louisville/Jefferson County entered into a revised 5-year franchise agreement (with renewal options). The franchise fee may be modified at Louisville/Jefferson County's election upon 60 days' notice. However, any franchise fee is capped at 3% of gross receipts for natural gas service within the franchise area. The agreement further provides that if the KPSC determines that the franchise fee should be recovered from LG&E's Louisville/Jefferson county customers in the franchise areas as a separate line item on their bill, the franchise fee will revert to zero. In August 2016, LG&E filed an application requesting the KPSC to review and rule upon the recoverability of the franchise fee. On March 14, 2018, the KPSC issued an Order authorizing the franchise fee to be recovered only from LG&E's Louisville/Jefferson County customers in the franchise area. As a result, the franchise fee will continue to be zero in accordance with the terms of the August 2016, 5-year gas franchise agreement. (PPL and PPL Electric) Pennsylvania Activities TCJA Impact on PPL Electric Rates On February 12, 2018, the PUC issued a Secretarial Letter requesting certain information from regulated utilities and inviting comment from interested parties on potential revision to customer rates as a result of enactment of the TCJA. PPL Electric submitted its response to the Secretarial Letter on March 9, 2018. On March 15, 2018, the PUC issued a Temporary Rates Order to allow time to determine the manner in which rates could be adjusted in response to the TCJA. The PUC issued another Temporary Rates Order on May 17, 2018 to address the impact of the TCJA and indicated that utilities without a currently pending general rate proceeding would receive a utility specific order. The PUC issued an Order specific to PPL Electric on May 17, 2018 that required PPL Electric to file a tariff or tariff supplement by June 15, 2018 to establish (a) temporary rates to be effective July 1, 2018, and (b) to record a deferred regulatory liability to reflect the tax savings associated with the TCJA for the period January 1 through June 30, 2018. On June 8, 2018, PPL Electric submitted a petition to the PUC to charge a negative surcharge of 7.05% to reflect the estimated 2018 tax savings associated with the TCJA. The PUC approved PPL Electric's petition on June 14, 2018 and PPL Electric filed a tariff on June 15, 2018 reflecting the increased negative surcharge. PPL Electric recorded a $41 million noncurrent regulatory liability and a corresponding reduction of revenue to be distributed to customers pursuant to a future rate adjustment related to the period January 1, 2018 through June 30, 2018. On March 15, 2018, the FERC issued a Notice of Inquiry seeking information on whether and how it should address changes to FERC-jurisdictional rates relating to accumulated deferred income taxes and bonus depreciation resulting from passage of the TCJA. On March 16, 2018, PPL Electric filed a waiver request, pursuant to Rule 207(a)(5) of the Rules of Practice and Procedure of the FERC, to accelerate incorporation of the changes to the federal corporate income tax rate in its transmission formula rate commencing on June 1, 2018 rather than allowing the TCJA tax rate reduction to be initially incorporated in PPL Electric's June 1, 2019 transmission formula rate. The waiver was approved on April 23, 2018 and PPL Electric submitted its transmission formula rate, reflecting the TCJA rate reduction, on April 27, 2018. In addition, on May 21, 2018, PPL Electric, as part of a PJM Transmission Owners joint filing, submitted comments in response to the FERC's March 15, 2018 Notice of Inquiry. The filing requested guidance on how the reduction in accumulated deferred income taxes, resulting from the TCJA reduced federal corporate income tax rate, should be treated for ratemaking purposes. On November 15, 2018, the FERC issued a Policy Statement which stated that the appropriate ratemaking treatment for changes in accumulated deferred income taxes as a result of the TCJA will be addressed in a Notice of Proposed Rulemaking. Also on November 15, 2018, the FERC issued the Notice of Proposed Rulemaking which proposes that public utility transmission providers should include mechanisms in their formula rates to deduct excess accumulated deferred income taxes from, or add deficient accumulated deferred income taxes to, rate base and adjust their income tax allowances by amortized excess or deficient accumulated deferred income taxes. The Notice of Proposed Rulemaking did not prescribe the mechanism companies should use to adjust their formula rates. PPL Electric is currently assessing the Notice of Proposed Rulemaking and is continuing to monitor guidance issued by the FERC. The changes, related to accumulated deferred income taxes impacting the transmission formula rate revenues, have not been significant since the new rate went into effect on June 1, 2018. Federal Matters (PPL and PPL Electric) FERC Formula Rate In April 2018, PPL Electric filed its annual transmission formula rate update with the FERC, reflecting a revised revenue requirement, which includes the impact of the TCJA. The filing establishes the revenue requirement used to set rates that took effect in June 2018. The time period for any challenges to PPL Electric's annual update has expired. No formal challenges were submitted. (PPL, LKE, LG&E and KU) FERC Transmission Rate Filing On August 3, 2018, LG&E and KU submitted an application to the FERC requesting elimination of certain on-going 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 seeks termination of LG&E's and KU's commitment to provide mitigation for certain horizontal market power concerns arising out of the 1998 merger for certain transmission service between MISO and LG&E and KU. The affected transmission customers are a limited number of municipal entities in Kentucky. The amounts at issue are generally waivers or credits for either LG&E and KU or for MISO transmission charges depending upon the direction of transmission service incurred by the municipalities. LG&E and KU estimate that such charges may average approximately $22 million annually, depending upon actual transmission customer and market volumes, structures and prices, with such charges allocated according to LG&E's and KU's respective transmission system ownership ratio. Due to the development of robust accessible energy markets over time, LG&E and KU believe the mitigation commitments are no longer relevant or appropriate. LG&E and KU currently receive recovery of such expenses in other rate mechanisms. LG&E and KU cannot predict the outcome of the proceeding, including any effects on their financial condition or results of operations. Transmission Customer Complaint On September 21, 2018, a transmission customer filed a complaint with the FERC against LG&E and KU alleging LG&E and KU have violated and continue to violate their obligations under an existing rate schedule to credit this customer for certain transmission charges from MISO. On October 11, 2018, LG&E and KU filed an answer to the complaint arguing such MISO transmission transactions are not covered by the rate schedule, and the amounts in question are not eligible for credits. LG&E and KU cannot predict the outcome of the proceeding, but believe that any potential required credits, including amounts currently reserved, would be subject to rate recovery. Other Purchase of Receivables Program (PPL and PPL Electric) In accordance with a PUC-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 2018, 2017 and 2016, PPL Electric purchased $1.3 billion, $1.3 billion and $1.4 billion of accounts receivable from alternative suppliers.

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