Utility Rate Regulation

12 Months Ended

Dec. 31, 2015

Utility Rate Regulation [Line Items]

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 that item will be recovered or refunded within a year of the balance sheet date.

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, VSCC and TRA.

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 coal contracts, power purchases and emission allowances. 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 will continue to reflect the original contracted prices for these 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 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
		2015		2014		2015		2014

Current Regulatory Assets:
	Environmental cost recovery	$	24	$	5
	Gas supply clause		1		15
	Transmission service charge		10		6	$	10	$	6
	Other		13		11		3		6
Total current regulatory assets (a)		$	48	$	37	$	13	$	12

Noncurrent Regulatory Assets:
	Defined benefit plans	$	809	$	720	$	469	$	372
	Taxes recoverable through future rates		326		316		326		316
	Storm costs		93		124		30		46
	Unamortized loss on debt		68		77		42		49
	Interest rate swaps		141		122
	Accumulated cost of removal of utility plant		137		114		137		114
	AROs		143		79
	Other		16		10		2
Total noncurrent regulatory assets		$	1,733	$	1,562	$	1,006	$	897

Current Regulatory Liabilities:
	Generation supply charge	$	41	$	28	$	41	$	28
	Demand side management		8		2
	Gas supply clause		6		6
	Transmission formula rate		48		42		48		42
	Fuel adjustment clause		14
	Storm damage expense		16		3		16		3
	Other		12		10		8		3
Total current regulatory liabilities		$	145	$	91	$	113	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	691	$	693
	Coal contracts (b)		17		59
	Power purchase agreement - OVEC (b)		83		92
	Net deferred tax assets		23		26
	Act 129 compliance rider		22		18	$	22	$	18
	Defined benefit plans		24		16
	Interest rate swaps		82		84
	Other		3		4
Total noncurrent regulatory liabilities		$	945	$	992	$	22	$	18

		LKE				LG&E				KU
		2015		2014		2015		2014		2015		2014

Current Regulatory Assets:
	Environmental cost recovery	$	24	$	5	$	13	$	4	$	11	$	1
	Gas supply clause		1		15		1		15
	Fuel adjustment clause				4				2				2
	Gas line tracker		1				1
	Other		9		1		1				8		1
Total current regulatory assets		$	35	$	25	$	16	$	21	$	19	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	340	$	348	$	215	$	215	$	125	$	133
	Storm costs		63		78		35		43		28		35
	Unamortized loss on debt		26		28		17		18		9		10
	Interest rate swaps		141		122		98		89		43		33
	AROs		143		79		57		28		86		51
	Plant retirement costs		6								6
	Other		8		10		2		4		6		6
Total noncurrent regulatory assets		$	727	$	665	$	424	$	397	$	303	$	268

Current Regulatory Liabilities:
	Demand side management		$	8	$	2	$	4	$	1	$	4	$	1
	Gas supply clause			6		6		6		6
	Fuel adjustment clause			14				2				12
	Gas line tracker					3				3
	Other			4		4		1				3		4
Total current regulatory liabilities			$	32	$	15	$	13	$	10	$	19	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	691	$	693	$	301	$	302	$	390	$	391
	Coal contracts (b)			17		59		7		25		10		34
	Power purchase agreement - OVEC (b)			83		92		57		63		26		29
	Net deferred tax assets			23		26		23		24				2
	Defined benefit plans			24		16						24		16
	Interest rate swaps			82		84		41		42		41		42
	Other			3		4		2		2		1		2
Total noncurrent regulatory liabilities			$	923	$	974	$	431	$	458	$	492	$	516

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

(b) These liabilities were recorded as offsets to certain intangible assets that were recorded at fair value upon the acquisition of LKE by PPL.

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 the portion of unrecognized transition obligation, 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 re-measured. Of the regulatory asset and liability balances recorded, costs of $46 million for PPL, $18 million for PPL Electric, $28 million for LKE, $19 million for LG&E and $9 million for KU are expected to be amortized into net periodic defined benefit costs in 2016 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 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, 2015, the balances were $10 million for PPL and LKE, $6 million for LG&E and $4 million for KU. Of the costs expected to be amortized into net periodic defined benefit costs in 2016, $10 million for PPL and LKE, $6 million for LG&E and $4 million for KU are expected to be recorded as a regulatory asset in 2016.

(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. 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, 2035 for LG&E and through 2040 for PPL, LKE and KU.

Accumulated Cost of Removal of Utility Plant

LG&E and KU accrue for 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.

(PPL and PPL Electric)

Generation Supply Charge

The generation supply charge 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 generation supply charge 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 quarter.

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. 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

In accordance with the PUC's December 2012 final rate case order, PPL Electric proposed the establishment of a Storm Damage Expense Rider (SDER) with the PUC. In April 2014, the PUC issued a final order approving the SDER with a January 1, 2015 effective date. On June 20, 2014, the Office of Consumer Advocate (OCA) filed a petition requesting the Commonwealth Court of Pennsylvania to reverse and remand the April 2014 order, which petition remains outstanding. On January 15, 2015, the PUC issued an order modifying the effective date of the SDER to February 1, 2015. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on 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 allows 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 allows PPL Electric to recover the maximum $185 million cost of the program over the three year period June 1, 2013 through May 31, 2016. 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 program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

(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 electric 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. As a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, LG&E and KU were authorized to earn a 10% return on equity for all their existing ECR plans. 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.

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 includes a separate natural gas procurement incentive mechanism, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indices between 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.

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 which are intended to reduce peak demand and delay the 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/demand conservation programs. The cost of DSM programs is assigned only to the class or classes of customers that benefit from the programs.

Interest Rate Swaps

(PPL, LKE, LG&E and KU)

Periodically, LG&E and KU enter into forward-starting interest rate swaps with PPL that have terms identical to forward-starting swaps entered into by PPL with third parties. Net realized gains and losses on all of these 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 will be recognized in “Interest Expense” on the Statements of Income over the life of the underlying debt at the time the underlying hedged interest expense is recorded. In September 2015, first mortgage bonds totaling $1.05 billion were issued (LG&E issued $550 million and KU issued $500 million) and all outstanding forward-starting interest rate swaps were terminated. Net cash settlements of $88 million were paid on the swaps that were terminated (LG&E and KU each paid $44 million). Net realized losses on these terminated swaps will be recovered through regulated rates. As such, the net settlements were recorded in regulatory assets and are being recognized in "Interest Expense" on the Statements of Income over the life of the new debt that matures in 2025 and 2045. There were no forward starting interest rate swaps outstanding at December 31, 2015. See Note 17 for additional information related to the forward-starting interest rate swaps.

Net cash settlements of $86 million were received on forward starting interest rate swaps that were terminated in 2013 (LG&E and KU each received $43 million). Net realized gains on these terminated swaps will be returned through regulated rates. As such, the net settlements were recorded as regulatory liabilities and are being recognized in "Interest Expense" on the Statements of Income over the life of the associated debt that matures in 2043.

(PPL, LKE and LG&E)

In addition to the terminated forward starting interest rate swaps, realized amounts associated with LG&E's other interest rate swaps, including a terminated swap contract from 2008, are recoverable through rates based on an order from the KPSC, LG&E's unrealized losses and gains are recorded as a regulatory asset or liability 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. Amortization of the gain or loss related to the 2008 terminated swap contract is to be recovered through 2035.

AROs

As discussed in Note 1, the accretion and depreciation expenses related to LG&E’s and KU’s AROs are recorded as a regulatory asset, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset is offset against the associated cost of removal regulatory liability, PP&E and ARO liability.

Gas Line Tracker

The GLT authorizes LG&E to recover its incremental operating expenses, depreciation, property taxes, and its 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 a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, LG&E is authorized to earn a 10% return on equity for the GLT mechanism. As part of this program, LG&E makes necessary repairs and assumes ownership of natural gas lines. LG&E annually files projected costs in October to become effective on the first billing cycle in January. After the completion of a plan year, LG&E submits a balancing adjustment filing to the KPSC to amend 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 timing differences.

Coal Contracts

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current market prices and offsets to regulatory liabilities for those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.

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.

Regulatory Liability Associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized.

Plant Retirement Costs

The 2014 Kentucky rate case settlement that became effective July 1, 2015, provided for deferred recovery of costs associated with Green River's remaining coal-fired generating units through their retirement date, which occurred in September 2015. These costs include inventory write-downs and separation benefits and will be amortized over three years.

Regulatory Matters

U.K. Activities (PPL)

RIIO-ED1

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

Ofgem Review of Line Loss Calculation

In 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, during 2014 WPD increased its liability by $65 million for over-recovery of line losses with a reduction to "Operating Revenues" on the Statement of Income. In 2013, WPD had recorded an increase of $45 million to the liability with a reduction to "Operating Revenues" on the Statement of Income. Other activity impacting the liability included reductions in the liability that have been included in tariffs and foreign exchange movements. WPD began refunding the liability to customers on April 1, 2015 and will continue through March 31, 2019. The liability at December 31, 2015 and 2014 was $61 million and $99 million.

Kentucky Activities

(PPL, LKE, LG&E and KU)

Rate Case Proceedings

On June 30, 2015, the KPSC approved a rate case settlement agreement providing for increases in the annual revenue requirements associated with KU base electricity rates of $125 million and LG&E base gas rates of $7 million. The annual revenue requirement associated with base electricity rates at LG&E was not changed. Although the settlement did not establish a specific return on equity with respect to the base rates, an authorized 10% return on equity will be utilized in the ECR and GLT mechanisms. The settlement agreement provides for deferred recovery of costs associated with KU's retirement of Green River Units 3 and 4. The new regulatory asset will be amortized over three years. The settlement also provides regulatory asset treatment for the difference between pension expense calculated in accordance with LG&E and KU’s pension accounting policy and pension expense using a 15 year amortization period for actuarial gains and losses. The new rates and all elements of the settlement became effective July 1, 2015.

KPSC Landfill Proceedings

On May 22, 2015, LG&E and KU filed an application with the KPSC for a declaratory order that the existing CPCN and ECR approvals regarding the initial phases of construction and rate recovery of the landfill for management of CCRs at the Trimble County Station remain in effect. The current design of the proposed landfill provides for construction in substantially the same location as originally proposed with approximately the same storage capacity and expected useful life. On May 20, 2015, the owner of an underground limestone mine filed a complaint with the KPSC requesting it to revoke the CPCN for the Trimble County landfill and limit recovery of costs for the Ghent Station landfill on the grounds that, as a result of cost increases, the proposed landfill no longer constitutes the least cost alternative for CCR management. The KPSC has initiated its own investigation, consolidated the proceedings, and ordered an accelerated procedural schedule. The KPSC conducted a hearing on the matter in September 2015. On December 15, 2015, the KPSC issued an order affirming LG&E and KU's existing CPCN and ECR authority for Phase 1 of the Trimble County and Ghent landfills and related facilities, and that the landfills are the least cost options for disposing of the combustion wastes. Additionally, the order requires LG&E and KU to file a CPCN prior to constructing Phases 2 and 3 at the Ghent landfill and Phases 2 through 4 at the Trimble County landfill. The order also requires LG&E and KU to submit status update reports every three months on Phase 1 of Trimble County landfill. Phase 1 of construction at Trimble County will commence after the required state permits are obtained. Phase 1 of the Ghent landfill was completed in December 2014.

CPCN and ECR Filings

On January 29, 2016, LG&E and KU submitted applications to the KPSC for CPCNs and for ECR rate treatment regarding upcoming environmental construction projects relating to the EPA's regulations addressing the handling of coal combustion byproducts and MATS. The construction projects are expected to begin in 2016 and continue through 2023 and are estimated to cost approximately $316 million at LG&E and $678 million at KU. The applications request an authorized 10% return on equity with respect to LG&E and KU's ECR mechanism consistent with the 2014 Kentucky rate case approved in June 2015.

Pennsylvania Activities (PPL and PPL Electric)

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms: the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it is in a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets

Rate Case Proceeding

On March 31, 2015, PPL Electric filed a request with the PUC for an increase in its annual distribution revenue requirement of approximately $167.5 million. The application was based on a fully projected future test year of January 1, 2016 through December 31, 2016. On September 3, 2015, PPL Electric filed with the PUC Administrative Law Judge a petition for approval of a settlement agreement under which PPL Electric would be permitted to increase its annual distribution rates by $124 million, effective January 1, 2016. On November 19, 2015, the PUC entered a final order adopting the Administrative Law Judge’s recommended decision. The new rates became effective January 1, 2016.

Distribution System Improvement Charge (DSIC)

On March 31, 2015, PPL Electric filed a petition requesting a waiver of the DSIC cap of 5% of billed revenues and approval to increase the maximum allowable DSIC from 5% to 7.5% for service rendered after January 1, 2016. PPL Electric filed the petition concurrently with its 2015 rate case and the Administrative Law Judge granted PPL Electric's request to consolidate these two proceedings. Under the terms of the settlement agreement discussed above, PPL Electric agreed to withdraw the petition without prejudice to re-file it at a later date.

In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC and, in an order entered on May 23, 2013, the PUC approved PPL Electric's proposed DSIC with an initial rate effective July 1, 2013, subject to refund after hearings. The PUC also assigned four technical recovery calculation issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. In November 2015, the PUC issued an opinion and order approving PPL Electric’s Petition with minor modifications.

Storm Damage Expense Rider (SDER)

In its December 2012 final rate case order, the PUC directed PPL Electric to file a proposed 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 recoup any differences from customers. In March 2013, PPL Electric filed its proposed SDER with the PUC and, as part of that filing, requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy. PPL Electric proposed that the SDER become effective January 1, 2013 at a zero rate with qualifying storm costs incurred in 2013 and the 2012 Hurricane Sandy costs be included in rates effective January 1, 2014. In April 2014, the PUC issued a final order approving the SDER with a January 1, 2015 effective date and initially including actual storm costs compared to collections for December 2013 through November 2014. As a result, PPL Electric reduced its regulatory liability by $12 million in March 2014. Also, as part of the April 2014 order, PPL Electric was authorized to recover Hurricane Sandy storm damage costs through the SDER of $29 million over a three-year period beginning January 1, 2015.

In June 2014, the Office of Consumer Advocate (OCA) filed a petition with the Commonwealth Court of Pennsylvania requesting that the Court reverse and remand the April 2014 order permitting PPL Electric to establish the SDER. In December 2015, the Commonwealth Court issued an Opinion affirming the PUC’s April 2014 Order. On January 15, 2015, the PUC issued a final order closing an investigation related to a separate OCA complaint concerning PPL Electric's October 2014 preliminary SDER calculation and modified the effective date of the SDER to February 1, 2015.

In the PUC rate case settlement agreement approved by the Commission 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 customers 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.

Act 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. 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 January 2016, PPL Electric and the other parties reached a settlement in principle. The settlement is subject to PUC approval. This matter remains pending before the PUC.

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. 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.

PPL Electric has received PUC approval of biannual DSP procurement plans for all periods required under Act 129. In January 2016, PPL Electric filed a Petition for Approval of a new DSP procurement plan with the PUC for the period June 1, 2017 through May 31, 2021. A Prehearing Conference is scheduled for March 2016. This proceeding remains pending before the PUC. PPL Electric cannot predict the outcome of this proceeding.

Smart Meter Rider (SMR)

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs are able to recover the costs of providing smart metering technology. All of PPL Electric's metered customers currently have advanced meters installed at their service locations capable of many of the functions required under Act 129. PPL Electric conducted pilot projects and technical evaluations of its current advanced metering technology and concluded that the current technology does not meet all of the requirements of Act 129. PPL Electric recovered the cost of its pilot programs and evaluations through a cost recovery mechanism, the Smart Meter Rider. In August 2013, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2013 and its planned actions for 2014. PPL Electric also submitted revised SMR charges that became effective January 1, 2014. In June 2014, PPL Electric filed its final Smart Meter Plan with the PUC. In that plan, PPL Electric proposes by the end of 2019 to replace all of its current meters with new meters that meet the Act 129 requirements. The total cost of the project is estimated to be approximately $471 million, of which approximately $406 million is expected to be capital. PPL Electric proposes to recover these costs through the SMR which the PUC previously approved for recovery of such costs. On April 30, 2015, the Administrative Law Judge assigned by the PUC to review PPL Electric's Smart Meter Plan issued a recommended decision approving the plan with minor modifications. On September 3, 2015, the PUC entered a final order approving the Smart Meter Plan with minor modifications.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM Open Access Transmission Tariff (OATT) that utilizes a formula-based rate recovery mechanism. The formula rate is calculated, in part, based on financial results as reported in PPL Electric’s annual FERC Form 1, filed under the FERC’s Uniform System of Accounts.

FERC Wholesale Formula Rates (LKE and KU)

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provided wholesale requirements power sales to 12 municipal customers. Among other changes, the application requests an amended formula whereby KU would charge cost-based rates with a subsequent true-up to actual costs, replacing the current formula which does not include a true-up. KU's application proposed an authorized return on equity of 10.7%. Certain elements, including the new formula rate, became effective April 23, 2014, subject to refund. In April 2014, nine municipalities submitted notices of termination, under the original notice period provisions, to cease taking power under the wholesale requirements contracts. Such terminations are to be effective in 2019, except in the case of one municipality with a 2017 effective date. In addition, a tenth municipality has become a transmission-only customer as of June 2015. In July 2014, KU agreed on settlement terms with the two municipal customers that did not provide termination notices and filed the settlement proposal with the FERC for its approval. In August 2014, the FERC issued an order on the interim settlement agreement allowing the proposed rates to become effective pending a final order. During the fourth quarter of 2015, the FERC approved the settlement agreement resolving the rate case with respect to these two municipalities, including approval of the formula rate with a true-up provision and authorizing a return on equity of 10% or the return on equity awarded to other parties in this case, whichever is lower. In August 2015, KU filed a partial settlement agreement with the nine terminating municipalities, resolving all but one open matter with one municipality. The settlement was approved by FERC in the fourth quarter of 2015, including authorizing the agreed-upon refunds, approving the formula rate with a true-up provision, and authorizing a 10.25% return on equity. Refunds to both the remaining municipals and the departing municipals were issued during the fourth quarter of 2015 totaling $3.4 million. A single remaining unresolved issue with one terminating municipality is in FERC litigation proceedings. Hearings on the dispute were conducted in January 2016 and preliminary rulings on the matter may occur in mid- or late-2016. KU cannot predict the ultimate outcome of this FERC proceeding, but the amounts under continuing dispute are not estimated to be significant.