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 for regulatory assets and liabilities related to the levelized fuel factor, 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 are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets.

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.



	PPL				PPL Electric
	2019		2018		2019		2018
Current Regulatory Assets:
Gas supply clause	$	8	$	12	$	—	$	—
Smart meter rider	13		11		13		11
Plant outage costs	32		10		—		—
Transmission formula rate	—		—		3		—
Transmission service charge	10		—		10		—
Other	4		3		—		—
Total current regulatory assets (a)	$	67	$	36	$	26	$	11

Noncurrent Regulatory Assets:
Defined benefit plans	$	800	$	963	$	467	$	558
Storm costs	39		56		15		22
Unamortized loss on debt	41		45		18		22
Interest rate swaps	22		20		—		—
Terminated interest rate swaps	81		87		—		—
Accumulated cost of removal of utility plant	220		200		220		200
AROs	279		273		—		—
Act 129 compliance rider	6		19		6		19
Other	4		10		—		3
Total noncurrent regulatory assets	$	1,492	$	1,673	$	726	$	824



	PPL				PPL Electric
	2019		2018		2019		2018
Current Regulatory Liabilities:
Generation supply charge	$	23	$	33	$	23	$	33
Transmission service charge	—		—		—		3
Environmental cost recovery	5		16		—		—
Universal service rider	9		27		9		27
Transmission formula rate	—		—		—		3
Fuel adjustment clause	8		—		—		—
TCJA customer refund	61		20		59		3
Storm damage expense rider	5		5		5		5
Generation formula rate	1		7		—		—
Other	3		14		—		—
Total current regulatory liabilities	$	115	$	122	$	96	$	74

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	640	$	674	$	—	$	—
Power purchase agreement - OVEC	51		59		—		—
Net deferred taxes	1,756		1,826		588		629
Defined benefit plans	51		37		11		5
Terminated interest rate swaps	68		72		—		—
TCJA customer refund	—		41		—		41
Other	6		5		—		—
Total noncurrent regulatory liabilities	$	2,572	$	2,714	$	599	$	675



	LKE				LG&E				KU
	2019		2018		2019		2018		2019		2018
Current Regulatory Assets:
Plant outage costs	$	32	$	10	$	16	$	7	$	16	$	3
Gas supply clause	8		12		8		12		—		—
Other	1		3		1		2		—		1
Total current regulatory assets	$	41	$	25	$	25	$	21	$	16	$	4

Noncurrent Regulatory Assets:
Defined benefit plans	$	333	$	405	$	206	$	249	$	127	$	156
Storm costs	24		34		14		20		10		14
Unamortized loss on debt	23		23		14		15		9		8
Interest rate swaps	22		20		22		20		—		—
Terminated interest rate swaps	81		87		47		51		34		36
AROs	279		273		76		75		203		198
Other	4		7		1		1		3		6
Total noncurrent regulatory assets	$	766	$	849	$	380	$	431	$	386	$	418



	LKE				LG&E				KU
	2019		2018		2019		2018		2019		2018
Current Regulatory Liabilities:
Environmental cost recovery	$	5	$	16	$	1	$	6	$	4	$	10
Fuel adjustment clauses	8		—		—		—		8		—
TCJA customer refund	2		17		—		7		2		10
Generation formula rate	1		7		—		—		1		7
Other	3		8		1		4		2		4
Total current regulatory liabilities	$	19	$	48	$	2	$	17	$	17	$	31

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	640	$	674	$	266	$	279	$	374	$	395
Power purchase agreement - OVEC	51		59		35		41		16		18
Net deferred taxes	1,168		1,197		544		557		624		640
Defined benefit plans	40		32		—		—		40		32
Terminated interest rate swaps	68		72		34		36		34		36
Other	6		5		4		2		2		3
Total noncurrent regulatory liabilities	$	1,973	$	2,039	$	883	$	915	$	1,090	$	1,124

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.

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, 2019, the balances were $51 million for PPL and LKE, $29 million for LG&E and $22 million for KU. As of December 31, 2018, the balances were $45 million for PPL and LKE, $25 million for LG&E and $20 million for KU.

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. LG&E's and KU's regulatory assets for storm costs are being amortized through various dates ending in 2029.

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 LG&E.

PPL Electric's current liability relates to two time periods. The liability of $16 million related to the period of July 1, 2018 through December 31, 2019 will be credited back to distribution customers through a negative surcharge. The liability of $43 million related to the period of January 1, 2018 through June 30, 2018 will be credited back to customers over the period of January 1, 2020 through December 31, 2020 utilizing the same negative surcharge mechanism referred to above, as approved by the PUC in November 2019.

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.

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.

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 are being amortized through 2021.

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.

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). 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.

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.

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 9.725% 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 or refunded within 12 months.

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 or refunded within 12 months.

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.

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. 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.

Since July 1, 2017, plant outage costs in Kentucky have been normalized for ratemaking purposes based on an average level of expenses. Plant outage expenses that are greater or less than the average are collected from or returned to customers, through future base rates. Effective May 1, 2019 plant outage costs are normalized based on a five-year average of historical expenses with over or under recoveries collected or returned over an eight-year period.

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 or refunded within 18 months.

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.

In September 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. LG&E's and KU's applications also sought to include changes associated with the TCJA and state tax reform in the calculation of the proposed base rates and to terminate the TCJA bill credit mechanism when new base rates would go into effect. The elimination of the TCJA bill credit mechanism will result in an estimated annual electricity revenue increase of approximately $58 million at KU and increases in electricity and gas revenues of approximately $40 million and $12 million at LG&E. The applications were based on a forecasted test year of May 1, 2019 through April 30, 2020 with a requested return-on-equity of 10.42%.

In March 2019, LG&E and KU, along with substantially all intervening parties to the proceeding, filed stipulation and recommendation agreements (stipulations) with the KPSC resolving all material issues with the parties. In addition to terminating the TCJA bill credit mechanism, the proposed stipulations provided for increases in annual revenue requirements associated with base electricity rates of approximately $58 million at KU and increases in annual base electricity and gas rates of approximately $4 million and $20 million at LG&E, based on a 9.725% return-on-equity.

On April 30, 2019, the KPSC issued orders ruling on open issues and approving the proposed stipulations filed in March 2019. The orders provide for increases in the revenue requirements associated with base electricity rates of $56 million at KU and increases associated with base electricity and gas rates of $2 million and $19 million at LG&E. With the termination of the TCJA bill credit mechanism, this represents annual revenue increases of $187 million ($114 million at KU and $73 million at LG&E). The new base rates and all elements of the orders became effective on May 1, 2019.

In 2018, LG&E and KU applied 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 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. 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. In March 2019, the FERC granted LG&E's and KU's request to remove the on-going credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, subject to FERC review and approval. In July 2019, LG&E and KU proposed their transition mechanism to the FERC and in September 2019, the FERC rejected the proposed transition mechanism and issued a separate order providing clarifications of certain aspects of the March order. In October 2019, LG&E and KU filed requests for rehearing and clarification on the two September orders. These rehearing requests are currently pending before FERC. Additionally, certain petitions for review of FERC's orders have been filed by multiple parties, including LG&E and KU, at the D.C. Circuit Court of Appeals. LG&E and KU cannot predict the outcome of the proceedings. LG&E and KU currently receive recovery of waivers and credits provided through other rate mechanisms.

In February 2019, PPL Electric filed with the FERC proposed revisions to its transmission formula rate template pursuant to Section 205 of the Federal Power Act and Section 35.13 of the FERC Rules and Regulations. Specifically, PPL Electric proposed to modify its formula rate to permit the return or recovery of excess or deficient ADIT resulting from the TCJA and permit PPL Electric to prospectively account for the income tax expense associated with the depreciation of the equity component of the AFUDC. In April 2019, the FERC accepted the proposed revisions to the formula rate template, which were effective June 1, 2019, as well as the proposed adjustments to ADIT, effective January 1, 2018.

In February 2019, in connection with the requirements of the TCJA and Kentucky HB 487, LG&E and KU filed a request with the FERC to amend their transmission formula rates resulting from the laws’ reductions to corporate income tax rates. The FERC approved this request effective June 1, 2019. LG&E and KU are currently reviewing the Final Rule and will submit a compliance filing addressing excess ADIT by June 1, 2020. LG&E and KU do not anticipate the impact of the TCJA and Kentucky HB 487 related to their FERC-jurisdictional rates to be significant.

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 2019, 2018 and 2017, PPL Electric purchased $1.2 billion, $1.3 billion and $1.3 billion of accounts receivable from alternative suppliers.