Utility Rate Regulation

3 Months Ended

Mar. 31, 2016

Utility Rate Regulation [Line Items]

6. Utility Rate Regulation

(All Registrants)

The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.

		PPL				PPL Electric
		March 31,		December 31,		March 31,		December 31,
		2016		2015		2016		2015

Current Regulatory Assets:
	Environmental cost recovery	$	6	$	24
	Transmission service charge		7		10	$	7	$	10
	Other		13		14		2		3
Total current regulatory assets (a)		$	26	$	48	$	9	$	13

Noncurrent Regulatory Assets:
	Defined benefit plans	$	801	$	809	$	465	$	469
	Taxes recoverable through future rates		328		326		328		326
	Storm costs		84		93		26		30
	Unamortized loss on debt		68		68		43		42
	Interest rate swaps		145		141
	Accumulated cost of removal of utility plant		139		137		139		137
	AROs		165		143
	Other		17		16		2		2
Total noncurrent regulatory assets		$	1,747	$	1,733	$	1,003	$	1,006

Current Regulatory Liabilities:
	Generation supply charge	$	30	$	41	$	30	$	41
	Demand side management		11		8
	Gas supply clause				6
	Universal service rider		6		5		6		5
	Transmission formula rate		37		48		37		48
	Fuel adjustment clause		16		14
	Storm damage expense		15		16		15		16
	Other		4		7		1		3
Total current regulatory liabilities		$	119	$	145	$	89	$	113

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	693	$	691
	Coal contracts (b)		14		17
	Power purchase agreement - OVEC (b)		82		83
	Net deferred tax assets		22		23
	Act 129 compliance rider		25		22	$	25	$	22
	Defined benefit plans		24		24
	Interest rate swaps		79		82
	Other		3		3
Total noncurrent regulatory liabilities		$	942	$	945	$	25	$	22

		LKE				LG&E				KU
		March 31,		December 31,		March 31,		December 31,		March 31,		December 31,
		2016		2015		2016		2015		2016		2015
Current Regulatory Assets:
	Environmental cost recovery	$	6	$	24	$	6	$	13			$	11
	Gas supply clause				1				1
	Gas line tracker		1		1		1		1
	Other		10		9				1	$	10		8
Total current regulatory assets		$	17	$	35	$	7	$	16	$	10	$	19

Noncurrent Regulatory Assets:
	Defined benefit plans	$	336	$	340	$	211	$	215	$	125	$	125
	Storm costs		58		63		32		35		26		28
	Unamortized loss on debt		25		26		16		17		9		9
	Interest rate swaps		145		141		103		98		42		43
	AROs		165		143		64		57		101		86
	Plant retirement costs		6		6						6		6
	Other		9		8		4		2		5		6
Total noncurrent regulatory assets		$	744	$	727	$	430	$	424	$	314	$	303

Current Regulatory Liabilities:
	Demand side management		$	11	$	8	$	5	$	4	$	6	$	4
	Gas supply clause					6				6
	Fuel adjustment clause			16		14		3		2		13		12
	Other			3		4				1		3		3
Total current regulatory liabilities			$	30	$	32	$	8	$	13	$	22	$	19

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	693	$	691	$	303	$	301	$	390	$	390
	Coal contracts (b)			14		17		6		7		8		10
	Power purchase agreement - OVEC (b)			82		83		57		57		25		26
	Net deferred tax assets			22		23		22		23
	Defined benefit plans			24		24						24		24
	Interest rate swaps			79		82		39		41		40		41
	Other			3		3		1		2		2		1
Total noncurrent regulatory liabilities			$	917	$	923	$	428	$	431	$	489	$	492

(a) 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.

Regulatory Matters

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

In 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. WPD began refunding its liability for over-recovery of line losses to customers on April 1, 2015 and will continue through March 31, 2019. The liability at March 31, 2016 was $45 million.

Kentucky Activities

CPCN and ECR Filings (PPL, LKE, LG&E and KU)

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’s and KU’s ECR mechanisms consistent with the 2014 Kentucky rate case approved in June 2015. Two parties have been granted intervenor status in the proceedings.

Gas Franchise (LKE and LG&E)

LG&E’s existing gas franchise agreement for the Louisville/Jefferson County service area expired on March 31, 2016. Pursuant to Kentucky law, upon expiration of a franchise, LG&E retains a revocable license to own and operate its facilities and to provide service. LG&E and city representatives are negotiating regarding a new franchise agreement and, in the interim, LG&E continues to provide gas service to customers in this service area at existing rates, but without collecting the prior franchise fee. LG&E cannot predict the outcome of this matter but does not anticipate that it will have a material effect on its financial condition or results of operation.

Pennsylvania Activities (PPL and PPL Electric)

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 of all major issues in the case and filed that settlement with the Administrative Law Judge. In March 2016, the PUC issued an Order approving PPL Electric’s Phase III Plan as modified by the settlement, allowing PPL Electric to recover a maximum $313 million in program cost over the five-year period June 1, 2016 through May 31, 2021 through the Act 129 compliance rider.

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. Hearings are scheduled for June 2016. This proceeding remains pending before the PUC. PPL Electric cannot predict the outcome of this proceeding.