6. 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 deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates. Therefore, no return is earned on the related assets.

KU's rates to municipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). 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. Therefore, 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
	2017		2016		2017		2016
Current Regulatory Assets:
Environmental cost recovery	$	5	$	6	$	—	$	—
Generation formula rate	6		11		—		—
Transmission service charge	—		7		—		7
Gas supply clause	4		3		—		—
Smart meter rider	15		6		15		6
Storm costs	—		5		—		5
Other	4		1		1		1
Total current regulatory assets (a)	$	34	$	39	$	16	$	19

Noncurrent Regulatory Assets:
Defined benefit plans	$	880	$	947	$	504	$	549
Taxes recoverable through future rates	3		340		3		340
Storm costs	33		57		—		9
Unamortized loss on debt	54		61		29		36
Interest rate swaps	26		31		—		—
Terminated interest rate swaps	92		98		—		—
Accumulated cost of removal of utility plant	173		159		173		159
AROs	234		211		—		—
Other	9		14		—		1
Total noncurrent regulatory assets	$	1,504	$	1,918	$	709	$	1,094



Current Regulatory Liabilities:
Generation supply charge	$	34	$	23	$	34	$	23
Transmission service charge	9		—		9		—
Universal service rider	26		14		26		14
Transmission formula rate	9		15		9		15
Fuel adjustment clauses	3		11		—		—
Act 129 compliance rider	—		17		—		17
Storm damage expense rider	8		13		8		13
Other	6		8		—		1
Total current regulatory liabilities	$	95	$	101	$	86	$	83

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	677	$	700	$	—	$	—
Power purchase agreement - OVEC (b)	68		75		—		—
Net deferred taxes (c)	1,853		23		668		—
Defined benefit plans	27		23		—		—
Terminated interest rate swaps	74		78		—		—
Other	5		—		—		—
Total noncurrent regulatory liabilities	$	2,704	$	899	$	668	$	—



	LKE				LG&E				KU
	2017		2016		2017		2016		2017		2016
Current Regulatory Assets:
Environmental cost recovery	$	5	$	6	$	5	$	6	$	—	$	—
Generation formula rate	6		11		—		—		6		11
Gas supply clause	4		3		4		3		—		—
Other	3		—		3		—		—		—
Total current regulatory assets	$	18	$	20	$	12	$	9	$	6	$	11



	LKE				LG&E				KU
	2017		2016		2017		2016		2017		2016

Noncurrent Regulatory Assets:
Defined benefit plans	$	376	$	398	$	234	$	246	$	142	$	152
Storm costs	33		48		18		26		15		22
Unamortized loss on debt	25		25		16		16		9		9
Interest rate swaps	26		31		26		31		—		—
Terminated interest rate swaps	92		98		54		57		38		41
AROs	234		211		61		70		173		141
Other	9		13		2		4		7		9
Total noncurrent regulatory assets	$	795	$	824	$	411	$	450	$	384	$	374



Current Regulatory Liabilities:
Demand side management	$	—	$	3	$	—	$	2	$	—	$	1
Fuel adjustment clause	3		11		—		2		3		9
Gas line tracker	3		—		3		—		—		—
Other	3		4		—		1		3		3
Total current regulatory liabilities	$	9	$	18	$	3	$	5	$	6	$	13

Noncurrent Regulatory Liabilities:
Accumulated cost of removal
of utility plant	$	677	$	700	$	282	$	305	$	395	$	395
Power purchase agreement - OVEC (b)	68		75		47		52		21		23
Net deferred taxes (c)	1,185		23		552		23		633		—
Defined benefit plans	27		23		—		—		27		23
Terminated interest rate swaps	74		78		37		39		37		39
Other	5		—		1		—		4		—
Total noncurrent regulatory liabilities	$	2,036	$	899	$	919	$	419	$	1,117	$	480


(a)	For PPL, these amounts are included in "Other current assets" on the Balance Sheets.


(b)	This liability was recorded as an offset to an intangible asset that was recorded at fair value upon the acquisition of LKE by PPL.


(c)	Primarily relates to excess deferred taxes recorded as a result of the TCJA, which lowered the federal corporate income tax rate effective January 1, 2018 requiring deferred tax balances and the associated regulatory liabilities to be remeasured as of December 31, 2017.

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. Of the regulatory asset and liability balances recorded, costs of $68 million for PPL, $30 million for PPL Electric, $38 million for LKE, $26 million for LG&E and $12 million for KU, are expected to be amortized into net periodic defined benefit costs in 2018 in accordance with PPL's, PPL Electric's, LKE's, LG&E's and KU's pension accounting policy.

(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, 2017, the balances were $33 million for PPL and LKE, $18 million for LG&E and $15 million for KU. As of December 31, 2016, the balances were $20 million for PPL and LKE, $11 million for LG&E and $9 million for KU. Of the costs expected to be amortized into net periodic defined benefit costs in 2018, $16 million for PPL and LKE, $10 million for LG&E and $6 million for KU, are expected to be recorded as a regulatory asset in 2018.

(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, LG&E's and KU's regulatory assets for storm costs are being amortized through various dates ending in 2020.

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 PPL, 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.

Regulatory Liability Associated with 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. At December 31, 2017, excess deferred taxes recorded as a result of the TCJA were $2.2 billion at PPL, $1.0 billion at PPL Electric, $1.2 billion at LKE, $532 million at LG&E and $634 million at KU, which include the gross-up associated with the excess deferred taxes.

(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 (energy and capacity and ancillary services), 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 $15 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 $15 million recovered annually through base rates. Beginning January 1, 2018, the amortized 2011 storm expense of $5 million will be included in the base rate component of the SDER.

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, Phase I of PPL Electric's energy efficiency and conservation plan was approved by a PUC order in October 2009. The order allowed PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May 31, 2013. Phase II of PPL's energy efficiency and conservation plan allowed PPL Electric to recover the maximum $185 million cost of the program over the three year period June 1, 2013 through May 31, 2016. Phase III of PPL's energy efficiency and conservation plan allows PPL Electric to recover the maximum $313 million over the next 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 Phase II program costs were reconciled at the end of the program and any remaining over- or under-recovery was rolled into Phase III. 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. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

Smart Meter Rider (SMR)

Act 129, which became effective November 14, 2008, 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). PPL Electric filed its initial SMP in 2009. However, in 2010, the PUC found that PPL Electric's "Advanced Metering Infrastructure" (AMI) system did not fully meet the standards of Act 129. In 2014, PPL Electric filed its current SMP, which was approved by the PUC in 2015. 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 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. In December 2017, the KPSC issued orders continuing the use of an authorized 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.

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.

Demand Side Management

LG&E's and KU's DSM programs consist of energy efficiency programs, intended to reduce peak demand and delay investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM provision, which includes a rate recovery mechanism that provides for concurrent recovery of DSM costs and incentives, and allows for the recovery of DSM revenues from lost sales associated with the DSM programs. Additionally, LG&E and KU earn an approved return on equity for capital expenditures associated with the residential and commercial load management and demand conservation programs. The cost of DSM programs is assigned only to the class or classes of customers that benefit from the programs.

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.

A net cash settlement of $9 million was paid on a swap that was terminated by LG&E in December 2016. The KPSC authorized the recording of a regulatory asset and the recovery of such costs. As part of the Stipulation to the 2016 Kentucky rate case that became effective July 1, 2017, the KPSC authorized LG&E to recover the swap termination payment through amortization of the regulatory asset using a straight-line method over 17 years. The amortization of the regulatory asset is recognized in "Interest Expense" on the Statements of Income.

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. These amounts are included in other current regulatory assets or 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 Rates

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 in July of each year utilizing a return on rate base calculation and actual expenses from the preceding year. The regulatory asset represents the difference between the revenue requirement in effect for the preceding year and actual expenditures incurred for the current year.

Regulatory Matters

(PPL)

U.K. Activities

RIIO-ED1

On April 1, 2015, the RIIO-ED1 eight-year price control period commenced for WPD's four DNOs.

(PPL, LKE, LG&E and KU)

Kentucky Activities

Rate Case Proceedings

In November 2016, LG&E and KU filed requests with the KPSC for increases in annual base electricity and gas rates. LG&E's and KU's applications included requests for CPCNs for implementing an Advanced Metering System program and a Distribution Automation program.

In April and May 2017, LG&E and KU, along with all intervening parties to the proceeding, filed with the KPSC, stipulation and recommendation agreements (stipulations) resolving all issues with the parties. Among other things, the proposed stipulations provided for increases in annual revenue requirements associated with LG&E base electricity rates of $59 million, LG&E base gas rates of $8 million and KU base electricity rates of $55 million, reflecting a return on equity of 9.75%, the withdrawal of LG&E's and KU's request for a CPCN for the Advanced Metering System and other changes to the revenue requirements, which dealt primarily with the timing of cost recovery, including depreciation rates.

In June 2017, the KPSC issued orders approving, with certain modifications, the proposed stipulations filed in April and May 2017. The orders modified the stipulations to provide for increases in annual revenue requirements associated with LG&E base electricity rates of $57 million, LG&E base gas rates of $7 million, KU base electricity rates of $52 million and incorporated an authorized return on equity of 9.7%. Consistent with the stipulations, the orders approved LG&E's and KU's request for implementing a Distribution Automation program and their withdrawal of a request for a CPCN for the Advanced Metering System program. The orders also approved new depreciation rates for LG&E and KU that resulted in higher depreciation of approximately $15 million ($4 million for LG&E and $11 million for KU) in 2017, exclusive of net additions to PP&E. The orders resulted in base electricity and gas rate increases of 5.2% and 2.1% at LG&E and a base electricity rate increase of 3.2% at KU. The new base rates and all elements of the orders became effective July 1, 2017. On June 23, 2017, the KPSC issued orders establishing an authorized return on equity of 9.7% for all of LG&E's and KU's existing approved ECR plans and projects, replacing the prior authorized return on equity levels of 9.8% for CCR projects and 10% for all other ECR approved projects, effective with bills issued in August 2017. The annual impact of the new authorized return for ECR projects is not expected to be significant.

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 full deployment is expected to be completed in 2021 with estimated capital costs of $155 million and $104 million for KU and LG&E electric service and $62 million for LG&E gas service. The full Advanced Metering Systems deployment will also result in incremental operation and maintenance costs during the deployment phase of $17 million and $11 million for KU and LG&E electric service and $3 million for LG&E gas service.

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 reducing 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 December 27, 2017, as a result of the complaint, the KPSC ordered LG&E and KU to satisfy or address the complaint and commence recording regulatory liabilities to reflect the reduction in the federal corporate tax rate to 21% and the associated savings in excess deferred taxes on an interim basis until utility rates are adjusted to reflect the federal tax savings.

On January 8, 2018, LG&E and KU responded to the complaint, denying certain claims in the complaint but concurring that the TCJA will result in savings for their customers. LG&E and KU have stated in their responses that the companies have recorded regulatory liabilities as of December 31, 2017 to reflect the reduction in the federal corporate tax rate and the associated savings in excess deferred taxes and will make changes to their ECR, DSM and LG&E's GLT rate mechanisms to begin providing the applicable savings to customers. LG&E and KU also offered to establish a new bill credit mechanism effective with the April 2018 billing cycle to begin distributing the tax savings associated with base rates to customers.

On January 29, 2018, LG&E and KU reached a settlement agreement to commence returning savings related to the TCJA to their customers. The savings will be distributed 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. The estimated impact of the rate reduction represents approximately $91 million in KU electricity revenues, $69 million in LG&E electricity revenues and $17 million in LG&E gas revenues for the period January 2018 through April 2019. Ongoing tax savings are expected to also be addressed in LG&E's and KU's next Kentucky base rate case. LG&E and KU have indicated their intent to file an application for base rate changes during 2018 to be effective during spring 2019. The settlement agreement is subject to review and approval by the KPSC. An order in the proceeding may occur during the first quarter of 2018.

Additionally, on January 8, 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.

The FERC has not issued any guidance on the effect on rates of the TCJA.

LG&E and KU cannot predict the outcome of these proceedings.

(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 franchise agreement with a five-year term (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 customers, the franchise fee shall revert to zero. In August 2016, LG&E filed an application in a KPSC proceeding to review and rule upon the recoverability of the franchise fee.

In August 2016, Louisville/Jefferson County submitted a motion to dismiss the proceeding filed by LG&E and, in November 2016, filed an amended complaint against LG&E relating to these issues. LG&E submitted KPSC filings to respond to, request dismissal of and consolidate certain claims or aspects of the proceedings. In January 2017, the KPSC issued an order denying Louisville/Jefferson County's motion to dismiss, consolidating the matter with LG&E's filed application and establishing a procedural schedule for the case. In September 2017, oral arguments were heard by the KPSC and a final order is expected in 2018. Until the KPSC issues a final order in this proceeding, LG&E cannot predict the ultimate outcome of this matter but does not anticipate that it will have a material effect on its financial condition or results of operation. LG&E continues to provide gas service to customers in this franchise area at existing rates, but without collecting or remitting a franchise fee.

(PPL and PPL Electric)

Pennsylvania Activities

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. In November 2015, PPL Electric filed with the PUC its Act 129 Phase III Energy Efficiency and Conservation Plan for the period June 1, 2016 through May 31, 2021. In June 2016, the PUC approved PPL Electric's Phase III Plan, allowing PPL Electric to implement its energy efficiency and demand response programs and recover, through the Act 129 compliance rider, the $313 million cost of the programs over the five-year period June 1, 2016 through May 31, 2021.

Act 129 also requires Default Service Providers (DSP) to provide electricity generation supply service to customers pursuant to a PUC-approved default service procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. PPL Electric is a DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of load unless otherwise approved by the PUC. A DSP is able to recover the costs associated with its default service procurement plan.

TCJA Impact on PPL Electric Rates (PPL and PPL Electric)

The PUC issued a Secretarial Letter on February 12, 2018 regarding the TCJA. The Commission is requesting comments from interested parties addressing whether the Commission should adjust current customer rates to reflect the reduced federal income tax expense and, if so, the appropriate negative surcharge or other methodology that would permit immediate adjustment to consumer rates, and whether the surcharge or other said methodology should provide that any refunds to customers due to reduced taxes be effective as of January 1, 2018. In addition, the Secretarial Letter requests certain Pennsylvania regulated utilities, including PPL Electric, to provide certain data related to the effect of the TCJA on PPL Electric’s income tax expense and rate base including whether any of the potential tax savings from the reduced federal corporate tax rate can be used for purposes other than to reduce customer rates. PPL Electric’s responses are due to the PUC not later than March 9, 2018.

The FERC has not issued any guidance on the effect on rates of the TCJA.

Federal Matters

FERC Formula Rate

In April 2017, PPL Electric filed its annual transmission formula rate update with the FERC, reflecting a revised revenue requirement. The filing establishes the revenue requirement used to set rates that took effect in June 2017. The time period for any challenges to PPL Electric's annual update has expired. No formal challenges were submitted.

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 2017, 2016 and 2015, PPL Electric purchased $1.3 billion, $1.4 billion and $1.3 billion of accounts receivable from unaffiliated third parties. During 2015, PPL Electric purchased $146 million of accounts receivable from PPL EnergyPlus. PPL Electric's purchases from PPL EnergyPlus for 2015 included purchases through May 31, 2015, which is the period during which PPL Electric and PPL EnergyPlus were affiliated entities. As a result of the June 1, 2015 spinoff of PPL Energy Supply and creation of Talen Energy, PPL EnergyPlus (renamed Talen Energy Marketing) is no longer an affiliate of PPL Electric. PPL Electric's purchases from Talen Energy Marketing subsequent to May 31, 2015 are included as purchases from unaffiliated third parties.