6. Utility Rate Regulation

(All Registrants except PPL Energy Supply)

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,
		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery			$	7
	Gas supply clause	$	19		10
	Fuel adjustment clause		10		2
	Demand side management		1		8
	Other		2		6	$	1	$	6
Total current regulatory assets		$	32	$	33	$	1	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	503	$	509	$	255	$	257
	Taxes recoverable through future rates		307		306		307		306
	Storm costs		141		147		51		53
	Unamortized loss on debt		82		85		54		57
	Interest rate swaps		48		44
	Accumulated cost of removal of utility plant		101		98		101		98
	AROs		51		44
	Other		12		13		2		1
Total noncurrent regulatory assets		$	1,245	$	1,246	$	770	$	772

Current Regulatory Liabilities:
	Generation supply charge	$	25	$	23	$	25	$	23
	Environmental cost recovery		3
	Gas supply clause		2		3
	Transmission service charge		10		8		10		8
	Fuel adjustment clause				4
	Transmission formula rate		27		20		27		20
	Universal service rider		5		10		5		10
	Storm damage expense				14				14
	Gas line tracker		7		6
	Other		1		2		1		1
Total current regulatory liabilities		$	80	$	90	$	68	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	692	$	688
	Coal contracts (a)		88		98
	Power purchase agreement - OVEC (a)		98		100
	Net deferred tax assets		30		30
	Act 129 compliance rider		13		15	$	13	$	15
	Defined benefit plans		26		26
	Interest rate swaps		86		86
	Other		4		5
Total noncurrent regulatory liabilities		$	1,037	$	1,048	$	13	$	15

		LKE				LG&E				KU
		March 31,		December 31,		March 31,		December 31,		March 31,		December 31,
		2014		2013		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery			$	7			$	2			$	5
	Gas supply clause	$	19		10	$	19		10
	Fuel adjustment clause		10		2		2		2	$	8
	Demand side management		1		8		1		3				5
	Other		1								1
Total current regulatory assets		$	31	$	27	$	22	$	17	$	9	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	248	$	252	$	161	$	164	$	87	$	88
	Storm costs		90		94		49		51		41		43
	Unamortized loss on debt		28		28		18		18		10		10
	Interest rate swaps		48		44		48		44
	AROs		51		44		23		21		28		23
	Other		10		12		4		5		6		7
Total noncurrent regulatory assets		$	475	$	474	$	303	$	303	$	172	$	171

Current Regulatory Liabilities:
		Environmental cost recovery	$	3							$	3
		Gas supply clause		2	$	3	$	2	$	3
		Fuel adjustment clause				4							$	4
		Gas line tracker		7		6		7		6
		Other				1								1
Total current regulatory liabilities			$	12	$	14	$	9	$	9	$	3	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	692	$	688	$	301	$	299	$	391	$	389
	Coal contracts (a)			88		98		38		43		50		55
	Power purchase agreement - OVEC (a)			98		100		68		69		30		31
	Net deferred tax assets			30		30		25		26		5		4
	Defined benefit plans			26		26						26		26
	Interest rate swaps			86		86		43		43		43		43
	Other			4		5		2		2		2		3
Total noncurrent regulatory liabilities			$	1,024	$	1,033	$	477	$	482	$	547	$	551

(a) 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 March 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, WPD increased its existing liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenue on the Statement of Income. The total recorded liability at March 31, 2014 was $115 million, nearly all of which will be refunded to customers from April 1, 2015 through March 31, 2019. The recorded liability at December 31, 2013 was $74 million. Other activity impacting the liability included reductions in the liability that have been included in tariffs during the first quarter of 2014 and foreign exchange movements. PPL is considering what, if any, recourse may be available to seek review of the final decision.

Kentucky Activities (PPL, LKE, LG&E and KU)

CPCN Filings

In January 2014, LG&E and KU filed an application for a CPCN with the KPSC requesting approval to build a NGCC generating unit at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site. The proceeding is currently in the discovery phase and a hearing is scheduled for July 2014. In April 2014, LG&E and KU filed a motion to hold further proceedings in abeyance for up to 90 days in order to allow the companies to assess the potential impact of certain events on their future capacity needs, including the recent receipt of termination notices to be generally effective in 2019 from certain KU municipal wholesale customers. See "Federal Matters - FERC Formula Rates" below for additional information relating to the municipal wholesale customers.

Pennsylvania Activities (PPL and PPL Electric)

Storm Damage Expense Rider

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER). 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 included in rates effective January 1, 2014. As of December 31, 2013, PPL Electric had a $14 million regulatory liability balance for amounts expected to be refunded to customers for revenues collected to cover storm costs in excess of actual storm costs incurred during 2013. On April 3, 2014, the PUC issued a final order approving the SDER. The SDER will be effective January 1, 2015 and will initially include actual storm costs compared to collections from December 2013 through November 2014. As a result of the order, PPL Electric reduced its regulatory liability by $12 million. Also, as part of the order, PPL Electric can recover Hurricane Sandy storm damage costs through the SDER over a three-year period beginning January 2015. See "Storm Costs" below for additional information on Hurricane Sandy costs.

Storm Costs

In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying costs in excess of insurance recoveries associated with Hurricane Sandy. At March 31, 2014 and December 31, 2013, $29 million was included on the Balance Sheets as a regulatory asset.

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.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. EDCs are able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's Phase I EE&C Plan ending May 31, 2013.

Phase I of Act 129 required EDCs to reduce overall electricity consumption by 1.0% by May 2011 and by 3.0% by May 2013, and reduce peak demand by 4.5% by May 2013. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction was required to occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. The PUC issued an Order on March 20, 2014 determining that PPL Electric met all of its Phase I EE&C compliance requirements.

Under Act 129 the PUC was required to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's Phase II reduction target is 2.1% of the total energy consumption forecasted by the PUC for the twelve months ended May 31, 2010. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric began its PUC-approved Phase II Plan implementation on June 1, 2013. In November 2013, PPL Electric filed 40 modifications to its Phase II Plan which contains programs designed to meet PPL Electric's target of reducing total energy consumption by 2.1%. On March 6, 2014, the PUC issued an order approving the revised EE&C Plan with minor modifications related to training.

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.

In January 2013, the PUC approved PPL Electric's DSP procurement plan for the period June 1, 2013 through May 31, 2015. On April 18, 2014, PPL Electric filed a new DSP procurement plan with the PUC for the period June 1, 2015 through May 31, 2017. This filing is pending before the PUC.

Smart Meter Rider

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 continues to conduct pilot projects to evaluate additional applications of its current advanced metering technology pursuant to the requirements of Act 129. PPL Electric recovers the cost of its pilot projects through a cost recovery mechanism, the Smart Meter Rider (SMR). 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. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

Distribution System Improvement Charge

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 begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC.

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. The case remains pending before the PUC.

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 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.

PPL Electric initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update was subsequently challenged by a group of municipal customers, whose challenges were opposed by PPL Electric. Between 2011 and 2013, numerous hearings before the FERC and settlement conferences were convened in an attempt to resolve these matters. Beginning in the second half of 2013, PPL Electric and the group of municipal customers exchanged confidential settlement proposals. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

FERC Formula Rates (LKE and KU)

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides 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, FERC accepted a motion filed by KU requesting a delay until mid-June of the effectiveness of other elements, including updated termination notice periods, new credit and uncollectible charge provisions. Also 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 to be effective in 2019, except in the case of one municipality with a conditional 2017 effective date. The parties are continuing settlement negotiations. KU cannot currently predict the outcome of the proceeding or related matters.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

(All Registrants except PPL Energy Supply)

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,
		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery			$	7
	Gas supply clause	$	19		10
	Fuel adjustment clause		10		2
	Demand side management		1		8
	Other		2		6	$	1	$	6
Total current regulatory assets		$	32	$	33	$	1	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	503	$	509	$	255	$	257
	Taxes recoverable through future rates		307		306		307		306
	Storm costs		141		147		51		53
	Unamortized loss on debt		82		85		54		57
	Interest rate swaps		48		44
	Accumulated cost of removal of utility plant		101		98		101		98
	AROs		51		44
	Other		12		13		2		1
Total noncurrent regulatory assets		$	1,245	$	1,246	$	770	$	772

Current Regulatory Liabilities:
	Generation supply charge	$	25	$	23	$	25	$	23
	Environmental cost recovery		3
	Gas supply clause		2		3
	Transmission service charge		10		8		10		8
	Fuel adjustment clause				4
	Transmission formula rate		27		20		27		20
	Universal service rider		5		10		5		10
	Storm damage expense				14				14
	Gas line tracker		7		6
	Other		1		2		1		1
Total current regulatory liabilities		$	80	$	90	$	68	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	692	$	688
	Coal contracts (a)		88		98
	Power purchase agreement - OVEC (a)		98		100
	Net deferred tax assets		30		30
	Act 129 compliance rider		13		15	$	13	$	15
	Defined benefit plans		26		26
	Interest rate swaps		86		86
	Other		4		5
Total noncurrent regulatory liabilities		$	1,037	$	1,048	$	13	$	15

		LKE				LG&E				KU
		March 31,		December 31,		March 31,		December 31,		March 31,		December 31,
		2014		2013		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery			$	7			$	2			$	5
	Gas supply clause	$	19		10	$	19		10
	Fuel adjustment clause		10		2		2		2	$	8
	Demand side management		1		8		1		3				5
	Other		1								1
Total current regulatory assets		$	31	$	27	$	22	$	17	$	9	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	248	$	252	$	161	$	164	$	87	$	88
	Storm costs		90		94		49		51		41		43
	Unamortized loss on debt		28		28		18		18		10		10
	Interest rate swaps		48		44		48		44
	AROs		51		44		23		21		28		23
	Other		10		12		4		5		6		7
Total noncurrent regulatory assets		$	475	$	474	$	303	$	303	$	172	$	171

Current Regulatory Liabilities:
		Environmental cost recovery	$	3							$	3
		Gas supply clause		2	$	3	$	2	$	3
		Fuel adjustment clause				4							$	4
		Gas line tracker		7		6		7		6
		Other				1								1
Total current regulatory liabilities			$	12	$	14	$	9	$	9	$	3	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	692	$	688	$	301	$	299	$	391	$	389
	Coal contracts (a)			88		98		38		43		50		55
	Power purchase agreement - OVEC (a)			98		100		68		69		30		31
	Net deferred tax assets			30		30		25		26		5		4
	Defined benefit plans			26		26						26		26
	Interest rate swaps			86		86		43		43		43		43
	Other			4		5		2		2		2		3
Total noncurrent regulatory liabilities			$	1,024	$	1,033	$	477	$	482	$	547	$	551

(a) 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 March 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, WPD increased its existing liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenue on the Statement of Income. The total recorded liability at March 31, 2014 was $115 million, nearly all of which will be refunded to customers from April 1, 2015 through March 31, 2019. The recorded liability at December 31, 2013 was $74 million. Other activity impacting the liability included reductions in the liability that have been included in tariffs during the first quarter of 2014 and foreign exchange movements. PPL is considering what, if any, recourse may be available to seek review of the final decision.

Kentucky Activities (PPL, LKE, LG&E and KU)

CPCN Filings

In January 2014, LG&E and KU filed an application for a CPCN with the KPSC requesting approval to build a NGCC generating unit at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site. The proceeding is currently in the discovery phase and a hearing is scheduled for July 2014. In April 2014, LG&E and KU filed a motion to hold further proceedings in abeyance for up to 90 days in order to allow the companies to assess the potential impact of certain events on their future capacity needs, including the recent receipt of termination notices to be generally effective in 2019 from certain KU municipal wholesale customers. See "Federal Matters - FERC Formula Rates" below for additional information relating to the municipal wholesale customers.

Pennsylvania Activities (PPL and PPL Electric)

Storm Damage Expense Rider

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER). 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 included in rates effective January 1, 2014. As of December 31, 2013, PPL Electric had a $14 million regulatory liability balance for amounts expected to be refunded to customers for revenues collected to cover storm costs in excess of actual storm costs incurred during 2013. On April 3, 2014, the PUC issued a final order approving the SDER. The SDER will be effective January 1, 2015 and will initially include actual storm costs compared to collections from December 2013 through November 2014. As a result of the order, PPL Electric reduced its regulatory liability by $12 million. Also, as part of the order, PPL Electric can recover Hurricane Sandy storm damage costs through the SDER over a three-year period beginning January 2015. See "Storm Costs" below for additional information on Hurricane Sandy costs.

Storm Costs

In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying costs in excess of insurance recoveries associated with Hurricane Sandy. At March 31, 2014 and December 31, 2013, $29 million was included on the Balance Sheets as a regulatory asset.

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.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. EDCs are able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's Phase I EE&C Plan ending May 31, 2013.

Phase I of Act 129 required EDCs to reduce overall electricity consumption by 1.0% by May 2011 and by 3.0% by May 2013, and reduce peak demand by 4.5% by May 2013. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction was required to occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. The PUC issued an Order on March 20, 2014 determining that PPL Electric met all of its Phase I EE&C compliance requirements.

Under Act 129 the PUC was required to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's Phase II reduction target is 2.1% of the total energy consumption forecasted by the PUC for the twelve months ended May 31, 2010. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric began its PUC-approved Phase II Plan implementation on June 1, 2013. In November 2013, PPL Electric filed 40 modifications to its Phase II Plan which contains programs designed to meet PPL Electric's target of reducing total energy consumption by 2.1%. On March 6, 2014, the PUC issued an order approving the revised EE&C Plan with minor modifications related to training.

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.

In January 2013, the PUC approved PPL Electric's DSP procurement plan for the period June 1, 2013 through May 31, 2015. On April 18, 2014, PPL Electric filed a new DSP procurement plan with the PUC for the period June 1, 2015 through May 31, 2017. This filing is pending before the PUC.

Smart Meter Rider

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 continues to conduct pilot projects to evaluate additional applications of its current advanced metering technology pursuant to the requirements of Act 129. PPL Electric recovers the cost of its pilot projects through a cost recovery mechanism, the Smart Meter Rider (SMR). 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. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

Distribution System Improvement Charge

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 begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC.

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. The case remains pending before the PUC.

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 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.

PPL Electric initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update was subsequently challenged by a group of municipal customers, whose challenges were opposed by PPL Electric. Between 2011 and 2013, numerous hearings before the FERC and settlement conferences were convened in an attempt to resolve these matters. Beginning in the second half of 2013, PPL Electric and the group of municipal customers exchanged confidential settlement proposals. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

FERC Formula Rates (LKE and KU)

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides 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, FERC accepted a motion filed by KU requesting a delay until mid-June of the effectiveness of other elements, including updated termination notice periods, new credit and uncollectible charge provisions. Also 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 to be effective in 2019, except in the case of one municipality with a conditional 2017 effective date. The parties are continuing settlement negotiations. KU cannot currently predict the outcome of the proceeding or related matters.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

(All Registrants except PPL Energy Supply)

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,
		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery			$	7
	Gas supply clause	$	19		10
	Fuel adjustment clause		10		2
	Demand side management		1		8
	Other		2		6	$	1	$	6
Total current regulatory assets		$	32	$	33	$	1	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	503	$	509	$	255	$	257
	Taxes recoverable through future rates		307		306		307		306
	Storm costs		141		147		51		53
	Unamortized loss on debt		82		85		54		57
	Interest rate swaps		48		44
	Accumulated cost of removal of utility plant		101		98		101		98
	AROs		51		44
	Other		12		13		2		1
Total noncurrent regulatory assets		$	1,245	$	1,246	$	770	$	772

Current Regulatory Liabilities:
	Generation supply charge	$	25	$	23	$	25	$	23
	Environmental cost recovery		3
	Gas supply clause		2		3
	Transmission service charge		10		8		10		8
	Fuel adjustment clause				4
	Transmission formula rate		27		20		27		20
	Universal service rider		5		10		5		10
	Storm damage expense				14				14
	Gas line tracker		7		6
	Other		1		2		1		1
Total current regulatory liabilities		$	80	$	90	$	68	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	692	$	688
	Coal contracts (a)		88		98
	Power purchase agreement - OVEC (a)		98		100
	Net deferred tax assets		30		30
	Act 129 compliance rider		13		15	$	13	$	15
	Defined benefit plans		26		26
	Interest rate swaps		86		86
	Other		4		5
Total noncurrent regulatory liabilities		$	1,037	$	1,048	$	13	$	15

		LKE				LG&E				KU
		March 31,		December 31,		March 31,		December 31,		March 31,		December 31,
		2014		2013		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery			$	7			$	2			$	5
	Gas supply clause	$	19		10	$	19		10
	Fuel adjustment clause		10		2		2		2	$	8
	Demand side management		1		8		1		3				5
	Other		1								1
Total current regulatory assets		$	31	$	27	$	22	$	17	$	9	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	248	$	252	$	161	$	164	$	87	$	88
	Storm costs		90		94		49		51		41		43
	Unamortized loss on debt		28		28		18		18		10		10
	Interest rate swaps		48		44		48		44
	AROs		51		44		23		21		28		23
	Other		10		12		4		5		6		7
Total noncurrent regulatory assets		$	475	$	474	$	303	$	303	$	172	$	171

Current Regulatory Liabilities:
		Environmental cost recovery	$	3							$	3
		Gas supply clause		2	$	3	$	2	$	3
		Fuel adjustment clause				4							$	4
		Gas line tracker		7		6		7		6
		Other				1								1
Total current regulatory liabilities			$	12	$	14	$	9	$	9	$	3	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	692	$	688	$	301	$	299	$	391	$	389
	Coal contracts (a)			88		98		38		43		50		55
	Power purchase agreement - OVEC (a)			98		100		68		69		30		31
	Net deferred tax assets			30		30		25		26		5		4
	Defined benefit plans			26		26						26		26
	Interest rate swaps			86		86		43		43		43		43
	Other			4		5		2		2		2		3
Total noncurrent regulatory liabilities			$	1,024	$	1,033	$	477	$	482	$	547	$	551

(a) 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 March 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, WPD increased its existing liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenue on the Statement of Income. The total recorded liability at March 31, 2014 was $115 million, nearly all of which will be refunded to customers from April 1, 2015 through March 31, 2019. The recorded liability at December 31, 2013 was $74 million. Other activity impacting the liability included reductions in the liability that have been included in tariffs during the first quarter of 2014 and foreign exchange movements. PPL is considering what, if any, recourse may be available to seek review of the final decision.

Kentucky Activities (PPL, LKE, LG&E and KU)

CPCN Filings

In January 2014, LG&E and KU filed an application for a CPCN with the KPSC requesting approval to build a NGCC generating unit at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site. The proceeding is currently in the discovery phase and a hearing is scheduled for July 2014. In April 2014, LG&E and KU filed a motion to hold further proceedings in abeyance for up to 90 days in order to allow the companies to assess the potential impact of certain events on their future capacity needs, including the recent receipt of termination notices to be generally effective in 2019 from certain KU municipal wholesale customers. See "Federal Matters - FERC Formula Rates" below for additional information relating to the municipal wholesale customers.

Pennsylvania Activities (PPL and PPL Electric)

Storm Damage Expense Rider

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER). 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 included in rates effective January 1, 2014. As of December 31, 2013, PPL Electric had a $14 million regulatory liability balance for amounts expected to be refunded to customers for revenues collected to cover storm costs in excess of actual storm costs incurred during 2013. On April 3, 2014, the PUC issued a final order approving the SDER. The SDER will be effective January 1, 2015 and will initially include actual storm costs compared to collections from December 2013 through November 2014. As a result of the order, PPL Electric reduced its regulatory liability by $12 million. Also, as part of the order, PPL Electric can recover Hurricane Sandy storm damage costs through the SDER over a three-year period beginning January 2015. See "Storm Costs" below for additional information on Hurricane Sandy costs.

Storm Costs

In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying costs in excess of insurance recoveries associated with Hurricane Sandy. At March 31, 2014 and December 31, 2013, $29 million was included on the Balance Sheets as a regulatory asset.

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.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. EDCs are able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's Phase I EE&C Plan ending May 31, 2013.

Phase I of Act 129 required EDCs to reduce overall electricity consumption by 1.0% by May 2011 and by 3.0% by May 2013, and reduce peak demand by 4.5% by May 2013. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction was required to occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. The PUC issued an Order on March 20, 2014 determining that PPL Electric met all of its Phase I EE&C compliance requirements.

Under Act 129 the PUC was required to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's Phase II reduction target is 2.1% of the total energy consumption forecasted by the PUC for the twelve months ended May 31, 2010. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric began its PUC-approved Phase II Plan implementation on June 1, 2013. In November 2013, PPL Electric filed 40 modifications to its Phase II Plan which contains programs designed to meet PPL Electric's target of reducing total energy consumption by 2.1%. On March 6, 2014, the PUC issued an order approving the revised EE&C Plan with minor modifications related to training.

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.

In January 2013, the PUC approved PPL Electric's DSP procurement plan for the period June 1, 2013 through May 31, 2015. On April 18, 2014, PPL Electric filed a new DSP procurement plan with the PUC for the period June 1, 2015 through May 31, 2017. This filing is pending before the PUC.

Smart Meter Rider

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 continues to conduct pilot projects to evaluate additional applications of its current advanced metering technology pursuant to the requirements of Act 129. PPL Electric recovers the cost of its pilot projects through a cost recovery mechanism, the Smart Meter Rider (SMR). 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. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

Distribution System Improvement Charge

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 begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC.

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. The case remains pending before the PUC.

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 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.

PPL Electric initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update was subsequently challenged by a group of municipal customers, whose challenges were opposed by PPL Electric. Between 2011 and 2013, numerous hearings before the FERC and settlement conferences were convened in an attempt to resolve these matters. Beginning in the second half of 2013, PPL Electric and the group of municipal customers exchanged confidential settlement proposals. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

FERC Formula Rates (LKE and KU)

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides 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, FERC accepted a motion filed by KU requesting a delay until mid-June of the effectiveness of other elements, including updated termination notice periods, new credit and uncollectible charge provisions. Also 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 to be effective in 2019, except in the case of one municipality with a conditional 2017 effective date. The parties are continuing settlement negotiations. KU cannot currently predict the outcome of the proceeding or related matters.