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
	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Current Regulatory Assets:
Environmental cost recovery	$	4	$	24	$	—	$	—
Generation formula rate	12		7		—		—
Transmission service charge	8		10		8		10
Other	6		7		4		3
Total current regulatory assets (a)	$	30	$	48	$	12	$	13

Noncurrent Regulatory Assets:
Defined benefit plans	$	791	$	809	$	456	$	469
Taxes recoverable through future rates	333		326		333		326
Storm costs	71		93		19		30
Unamortized loss on debt	62		68		39		42
Interest rate swaps	143		141		—		—
Accumulated cost of removal of utility plant	143		137		143		137
AROs	208		143		—		—
Other	14		16		1		2
Total noncurrent regulatory assets	$	1,765	$	1,733	$	991	$	1,006



Current Regulatory Liabilities:
Generation supply charge	$	22	$	41	$	22	$	41
Demand side management	6		8		—		—
Gas supply clause	—		6		—		—
Universal service rider	10		5		10		5
Transmission formula rate	25		48		25		48
Fuel adjustment clause	14		14		—		—
Act 129 compliance rider	22		—		22		—
Storm damage expense	13		16		13		16
Other	8		7		2		3
Total current regulatory liabilities	$	120	$	145	$	94	$	113

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	698	$	691	$	—	$	—
Coal contracts (b)	3		17		—		—
Power purchase agreement - OVEC (b)	77		83		—		—
Net deferred tax assets	23		23		—		—
Act 129 compliance rider	—		22		—		22
Defined benefit plans	27		24		—		—
Interest rate swaps	80		82		—		—
Other	3		3		—		—
Total noncurrent regulatory liabilities	$	911	$	945	$	—	$	22



	LKE				LG&E				KU
	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Current Regulatory Assets:
Environmental cost recovery	$	4	$	24	$	4	$	13	$	—	$	11
Generation formula rate	12		7		—		—		12		7
Other	2		4		2		3		—		1



	LKE				LG&E				KU
	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Total current regulatory assets	$	18	$	35	$	6	$	16	$	12	$	19

Noncurrent Regulatory Assets:
Defined benefit plans	$	335	$	340	$	211	$	215	$	124	$	125
Storm costs	52		63		29		35		23		28
Unamortized loss on debt	23		26		16		17		7		9
Interest rate swaps	143		141		102		98		41		43
AROs	208		143		77		57		131		86
Plant retirement costs	4		6		—		—		4		6
Other	9		8		2		2		7		6
Total noncurrent regulatory assets	$	774	$	727	$	437	$	424	$	337	$	303



Current Regulatory Liabilities:
Demand side management	$	6	$	8	$	4	$	4	$	2	$	4
Gas supply clause	—		6		—		6		—		—
Fuel adjustment clause	14		14		2		2		12		12
Other	6		4		1		1		5		3
Total current regulatory liabilities	$	26	$	32	$	7	$	13	$	19	$	19

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	698	$	691	$	306	$	301	$	392	$	390
Coal contracts (b)	3		17		1		7		2		10
Power purchase agreement - OVEC (b)	77		83		53		57		24		26
Net deferred tax assets	23		23		23		23		—		—
Defined benefit plans	27		24		—		—		27		24
Interest rate swaps	80		82		40		41		40		41
Other	3		3		1		2		2		1
Total noncurrent regulatory liabilities	$	911	$	923	$	424	$	431	$	487	$	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, which will continue through March 31, 2019. The liability at September 30, 2016 was $31 million.

Kentucky Activities

Rate Case Proceedings (PPL, LKE, LG&E and KU)

On November 1, 2016, LG&E and KU announced that on November 23, 2016, they anticipate filing requests with the KPSC for increases in annual base electricity rates of approximately $103 million at KU and an increase in annual base electricity and gas rates of approximately $94 million and $14 million at LG&E. The proposed base rate increases to be requested are an electricity rate increase of 6.4% at KU and electricity and gas rate increases of 8.5% and 4.2% at LG&E and would become effective in July 2017. LG&E's and KU's applications include requests for CPCNs for implementing an Advanced Metering System program and a Distribution Automation program. The applications are to be based on a forecasted test year of July 1, 2017 through June 30, 2018 and a requested return-on-equity of 10.23%. LG&E and KU cannot predict the outcome of these proceedings.

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

On August 8, 2016, the KPSC issued an order approving CPCNs and ECR rate treatment regarding environmental construction projects relating to the EPA's regulations addressing the handling of coal combustion by-products and MATS. The construction projects began in 2016 and are expected to continue through 2023. The KPSC order established a 9.8% authorized return on equity for these projects. Recovery of costs has commenced with bills rendered on and after August 31, 2016.

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. LG&E submitted a proposed bid for a new franchise agreement on June 9, 2016. On August 30, 2016, LG&E and Louisville/Jefferson County entered into a revised franchise agreement with a 5-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. On August 30, 2016, LG&E filed an application in a KPSC proceeding to review and rule upon the recoverability of the franchise fee.

Louisville/Jefferson County submitted a motion to dismiss the proceeding filed by LG&E, and further filed a KPSC complaint against LG&E relating to these issues. On October 19, 2016, the KPSC issued an order rejecting Louisville/Jefferson County's complaint and provided Louisville/Jefferson County 20 days to file an amended complaint. Until the KPSC issues orders in these proceedings, 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. LG&E continues to provide gas service to customers in this franchise area at existing rates, but without collecting or remitting a franchise fee.

Pennsylvania Activities (PPL and PPL Electric)

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 January 2016, PPL Electric and the other parties to the case reached a settlement of all major issues and filed that settlement with the Administrative Law Judge. In June 2016, the PUC issued a final order approving PPL Electric's Phase III Plan as modified by the settlement, allowing PPL Electric to recover, through the Act 129 compliance rider, a maximum $313 million in program cost 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. 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 its biannual DSP procurement plans for all prior 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. The parties to the proceeding reached a settlement on all but one issue and a partial settlement agreement and briefs on the open issue were submitted to the Administrative Law Judge (ALJ) in July 2016. In August 2016, the ALJ issued an initial decision, and certain parties filed exceptions and reply exceptions. In October 2016, the PUC issued an order approving the partial settlement agreement and adopting the initial decision with minor modifications.