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
		September 30,		December 31,		September 30,		December 31,
		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery	$	3	$	7
	Gas supply clause		20		10
	Fuel adjustment clause				2
	Demand side management				8
	Other		5		6	$	3	$	6
Total current regulatory assets		$	28	$	33	$	3	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	486	$	509	$	250	$	257
	Taxes recoverable through future rates		313		306		313		306
	Storm costs		130		147		47		53
	Unamortized loss on debt		79		85		51		57
	Interest rate swaps		54		44
	Accumulated cost of removal of utility plant		111		98		111		98
	AROs		72		44
	Other		8		13				1
Total noncurrent regulatory assets		$	1,253	$	1,246	$	772	$	772

Current Regulatory Liabilities:
	Generation supply charge	$	33	$	23	$	33	$	23
	Gas supply clause		4		3
	Transmission service charge		2		8		2		8
	Fuel adjustment clause		1		4
	Transmission formula rate		42		20		42		20
	Universal service rider				10				10
	Storm damage expense		1		14		1		14
	Gas line tracker		5		6
	Other		4		2		3		1
Total current regulatory liabilities		$	92	$	90	$	81	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	697	$	688
	Coal contracts (a)		69		98
	Power purchase agreement - OVEC (a)		94		100
	Net deferred tax assets		27		30
	Act 129 compliance rider		18		15	$	18	$	15
	Defined benefit plans		29		26
	Interest rate swaps		90		86
	Other		4		5
Total noncurrent regulatory liabilities		$	1,028	$	1,048	$	18	$	15

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2014		2013		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery	$	3	$	7	$	3	$	2			$	5
	Gas supply clause		20		10		20		10
	Fuel adjustment clause				2				2
	Demand side management				8				3				5
	Other		2							$	2
Total current regulatory assets		$	25	$	27	$	23	$	17	$	2	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	236	$	252	$	159	$	164	$	77	$	88
	Storm costs		83		94		45		51		38		43
	Unamortized loss on debt		28		28		18		18		10		10
	Interest rate swaps		54		44		52		44		2
	AROs		72		44		27		21		45		23
	Other		8		12		4		5		4		7
Total noncurrent regulatory assets		$	481	$	474	$	305	$	303	$	176	$	171

Current Regulatory Liabilities:
		Gas supply clause	$	4	$	3	$	4	$	3
		Fuel adjustment clause		1		4					$	1	$	4
		Gas line tracker		5		6		5		6
		Other		1		1						1		1
Total current regulatory liabilities			$	11	$	14	$	9	$	9	$	2	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	697	$	688	$	305	$	299	$	392	$	389
	Coal contracts (a)			69		98		30		43		39		55
	Power purchase agreement - OVEC (a)			94		100		65		69		29		31
	Net deferred tax assets			27		30		24		26		3		4
	Defined benefit plans			29		26						29		26
	Interest rate swaps			90		86		45		43		45		43
	Other			4		5		2		2		2		3
Total noncurrent regulatory liabilities			$	1,010	$	1,033	$	471	$	482	$	539	$	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, during the first quarter of 2014 WPD increased its existing liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenues on the Statement of Income. The total recorded liability at September 30, 2014 was $105 million, 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 and foreign exchange movements. In June 2014, WPD applied for judicial review of certain of Ofgem's decisions related to closing out the DPCR4 line loss mechanism. The court has set a hearing for November 20, 2014 to hear WPD's application for permission to seek judicial review. The primary relief sought is for Ofgem to reconsider the overall proportionality of penalties imposed on WPD. The entire process could last through the second quarter of 2015. PPL cannot predict the outcome of this matter.

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 an NGCC generating unit, Green River Unit 5, at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site. In April 2014, LG&E and KU filed a motion to hold further proceedings in abeyance to allow the companies to assess the potential impact of certain events on their future capacity needs, including the receipt of termination notices to be generally effective in 2019 from certain KU municipal wholesale customers. In August 2014, LG&E and KU submitted a motion to withdraw their request to construct the Green River NGCC and the KPSC issued an order granting that request. LG&E’s and KU’s CPCN application continues to request approval to construct the E. W. Brown solar generating facility. LG&E and KU entered into a stipulation in this proceeding agreeing to certain matters with some interveners. A hearing is scheduled to be held in November 2014, and a final order is anticipated before the end of the year. See "Federal Matters - FERC Wholesale Formula Rates" below for additional information relating to the municipal wholesale customers.

Rate Case Proceedings

On November 4, 2014, LG&E and KU announced that on November 26, 2014, they anticipate filing requests with the KPSC for increases in annual base electricity rates of approximately $30 million at LG&E and approximately $153 million at KU and an increase in annual base gas rates of approximately $14 million at LG&E. The proposed base rate increases would result in electricity rate increases of 2.7% at LG&E and 9.6% at KU and a gas rate increase of 4.2% at LG&E and would become effective in July 2015. LG&E’s and KU’s applications each include a request for authorized returns-on-equity of 10.50%. The applications are based on a forecasted test year of July 1, 2015 through June 30, 2016. LG&E and KU cannot predict the outcome of these proceedings.

Pennsylvania Activities (PPL and PPL Electric)

Storm Damage Expense Rider

In its December 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. In April 2014, the PUC issued a final order approving the SDER. The SDER will be effective January 1, 2015 and 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. On June 20, 2014, the Office of Consumer Advocate filed a petition for review of the April 2014 order with the Commonwealth Court of Pennsylvania. The case remains pending. 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 September 30, 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.

Act 129 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. In April 2014, PPL Electric filed a new DSP procurement plan with the PUC for the period June 1, 2015 through May 31, 2017. In September 2014, the parties filed with the presiding Administrative Law Judge a partial settlement resolving all but two issues in the proceeding related to the structure of the DSP, without direct financial impact on PPL Electric. The parties filed briefs on those two issues. In October 2014, a Recommended Decision was issued approving the partial settlement. This proceeding remains pending before the PUC but is not expected to have a material impact on PPL Electric.

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 conducted pilot projects and technical evaluations of its current advanced metering technology and concluded that the current technology does not meet all of the Act 129 requirements. PPL Electric recovered the cost of its evaluations 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. On June 30, 2014, PPL Electric filed its final Smart Meter Plan with the PUC. In that plan, PPL Electric proposes to replace all of its current meters with advanced meters that meet the Act 129 requirements. Full deployment of the new meters is expected to be complete by the end of 2019. The total cost of the project is estimated to be approximately $450 million. PPL Electric proposes to recover these costs through the SMR which the PUC previously has approved for recovery of such costs. The PUC assigned PPL Electric’s plan to an Administrative Law Judge for hearings and preparation of a recommended decision. PPL Electric cannot predict the outcome of this proceeding.

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. In August 2014, the presiding Administrative Law Judge issued a recommended decision which would not have a significant impact on PPL Electric. This matter 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. In September 2014, the parties filed a Joint Offer of Settlement with the FERC resolving all issues in the pending challenges, and including refunds of certain insignificant amounts to the municipalities. The settlement judge certified the uncontested settlement to the FERC with a recommendation that it be approved.

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 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, 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 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. If approved, the settlement agreement will resolve the rate case with respect to these two municipalities, including an authorized return on equity of 10% or the return on equity awarded to other parties in this case, whichever is lower. Also in July 2014, KU made a contractually required filing with the FERC that addressed certain rate recovery matters affecting the nine terminating municipalities during the remaining term of their contracts. KU and the terminating municipalities continue settlement discussions in this proceeding. KU cannot currently predict the outcome of its FERC applications regarding its wholesale power agreements with the municipalities.

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
		September 30,		December 31,		September 30,		December 31,
		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery	$	3	$	7
	Gas supply clause		20		10
	Fuel adjustment clause				2
	Demand side management				8
	Other		5		6	$	3	$	6
Total current regulatory assets		$	28	$	33	$	3	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	486	$	509	$	250	$	257
	Taxes recoverable through future rates		313		306		313		306
	Storm costs		130		147		47		53
	Unamortized loss on debt		79		85		51		57
	Interest rate swaps		54		44
	Accumulated cost of removal of utility plant		111		98		111		98
	AROs		72		44
	Other		8		13				1
Total noncurrent regulatory assets		$	1,253	$	1,246	$	772	$	772

Current Regulatory Liabilities:
	Generation supply charge	$	33	$	23	$	33	$	23
	Gas supply clause		4		3
	Transmission service charge		2		8		2		8
	Fuel adjustment clause		1		4
	Transmission formula rate		42		20		42		20
	Universal service rider				10				10
	Storm damage expense		1		14		1		14
	Gas line tracker		5		6
	Other		4		2		3		1
Total current regulatory liabilities		$	92	$	90	$	81	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	697	$	688
	Coal contracts (a)		69		98
	Power purchase agreement - OVEC (a)		94		100
	Net deferred tax assets		27		30
	Act 129 compliance rider		18		15	$	18	$	15
	Defined benefit plans		29		26
	Interest rate swaps		90		86
	Other		4		5
Total noncurrent regulatory liabilities		$	1,028	$	1,048	$	18	$	15

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2014		2013		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery	$	3	$	7	$	3	$	2			$	5
	Gas supply clause		20		10		20		10
	Fuel adjustment clause				2				2
	Demand side management				8				3				5
	Other		2							$	2
Total current regulatory assets		$	25	$	27	$	23	$	17	$	2	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	236	$	252	$	159	$	164	$	77	$	88
	Storm costs		83		94		45		51		38		43
	Unamortized loss on debt		28		28		18		18		10		10
	Interest rate swaps		54		44		52		44		2
	AROs		72		44		27		21		45		23
	Other		8		12		4		5		4		7
Total noncurrent regulatory assets		$	481	$	474	$	305	$	303	$	176	$	171

Current Regulatory Liabilities:
		Gas supply clause	$	4	$	3	$	4	$	3
		Fuel adjustment clause		1		4					$	1	$	4
		Gas line tracker		5		6		5		6
		Other		1		1						1		1
Total current regulatory liabilities			$	11	$	14	$	9	$	9	$	2	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	697	$	688	$	305	$	299	$	392	$	389
	Coal contracts (a)			69		98		30		43		39		55
	Power purchase agreement - OVEC (a)			94		100		65		69		29		31
	Net deferred tax assets			27		30		24		26		3		4
	Defined benefit plans			29		26						29		26
	Interest rate swaps			90		86		45		43		45		43
	Other			4		5		2		2		2		3
Total noncurrent regulatory liabilities			$	1,010	$	1,033	$	471	$	482	$	539	$	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, during the first quarter of 2014 WPD increased its existing liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenues on the Statement of Income. The total recorded liability at September 30, 2014 was $105 million, 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 and foreign exchange movements. In June 2014, WPD applied for judicial review of certain of Ofgem's decisions related to closing out the DPCR4 line loss mechanism. The court has set a hearing for November 20, 2014 to hear WPD's application for permission to seek judicial review. The primary relief sought is for Ofgem to reconsider the overall proportionality of penalties imposed on WPD. The entire process could last through the second quarter of 2015. PPL cannot predict the outcome of this matter.

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 an NGCC generating unit, Green River Unit 5, at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site. In April 2014, LG&E and KU filed a motion to hold further proceedings in abeyance to allow the companies to assess the potential impact of certain events on their future capacity needs, including the receipt of termination notices to be generally effective in 2019 from certain KU municipal wholesale customers. In August 2014, LG&E and KU submitted a motion to withdraw their request to construct the Green River NGCC and the KPSC issued an order granting that request. LG&E’s and KU’s CPCN application continues to request approval to construct the E. W. Brown solar generating facility. LG&E and KU entered into a stipulation in this proceeding agreeing to certain matters with some interveners. A hearing is scheduled to be held in November 2014, and a final order is anticipated before the end of the year. See "Federal Matters - FERC Wholesale Formula Rates" below for additional information relating to the municipal wholesale customers.

Rate Case Proceedings

On November 4, 2014, LG&E and KU announced that on November 26, 2014, they anticipate filing requests with the KPSC for increases in annual base electricity rates of approximately $30 million at LG&E and approximately $153 million at KU and an increase in annual base gas rates of approximately $14 million at LG&E. The proposed base rate increases would result in electricity rate increases of 2.7% at LG&E and 9.6% at KU and a gas rate increase of 4.2% at LG&E and would become effective in July 2015. LG&E’s and KU’s applications each include a request for authorized returns-on-equity of 10.50%. The applications are based on a forecasted test year of July 1, 2015 through June 30, 2016. LG&E and KU cannot predict the outcome of these proceedings.

Pennsylvania Activities (PPL and PPL Electric)

Storm Damage Expense Rider

In its December 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. In April 2014, the PUC issued a final order approving the SDER. The SDER will be effective January 1, 2015 and 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. On June 20, 2014, the Office of Consumer Advocate filed a petition for review of the April 2014 order with the Commonwealth Court of Pennsylvania. The case remains pending. 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 September 30, 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.

Act 129 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. In April 2014, PPL Electric filed a new DSP procurement plan with the PUC for the period June 1, 2015 through May 31, 2017. In September 2014, the parties filed with the presiding Administrative Law Judge a partial settlement resolving all but two issues in the proceeding related to the structure of the DSP, without direct financial impact on PPL Electric. The parties filed briefs on those two issues. In October 2014, a Recommended Decision was issued approving the partial settlement. This proceeding remains pending before the PUC but is not expected to have a material impact on PPL Electric.

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 conducted pilot projects and technical evaluations of its current advanced metering technology and concluded that the current technology does not meet all of the Act 129 requirements. PPL Electric recovered the cost of its evaluations 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. On June 30, 2014, PPL Electric filed its final Smart Meter Plan with the PUC. In that plan, PPL Electric proposes to replace all of its current meters with advanced meters that meet the Act 129 requirements. Full deployment of the new meters is expected to be complete by the end of 2019. The total cost of the project is estimated to be approximately $450 million. PPL Electric proposes to recover these costs through the SMR which the PUC previously has approved for recovery of such costs. The PUC assigned PPL Electric’s plan to an Administrative Law Judge for hearings and preparation of a recommended decision. PPL Electric cannot predict the outcome of this proceeding.

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. In August 2014, the presiding Administrative Law Judge issued a recommended decision which would not have a significant impact on PPL Electric. This matter 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. In September 2014, the parties filed a Joint Offer of Settlement with the FERC resolving all issues in the pending challenges, and including refunds of certain insignificant amounts to the municipalities. The settlement judge certified the uncontested settlement to the FERC with a recommendation that it be approved.

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 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, 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 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. If approved, the settlement agreement will resolve the rate case with respect to these two municipalities, including an authorized return on equity of 10% or the return on equity awarded to other parties in this case, whichever is lower. Also in July 2014, KU made a contractually required filing with the FERC that addressed certain rate recovery matters affecting the nine terminating municipalities during the remaining term of their contracts. KU and the terminating municipalities continue settlement discussions in this proceeding. KU cannot currently predict the outcome of its FERC applications regarding its wholesale power agreements with the municipalities.

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
		September 30,		December 31,		September 30,		December 31,
		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery	$	3	$	7
	Gas supply clause		20		10
	Fuel adjustment clause				2
	Demand side management				8
	Other		5		6	$	3	$	6
Total current regulatory assets		$	28	$	33	$	3	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	486	$	509	$	250	$	257
	Taxes recoverable through future rates		313		306		313		306
	Storm costs		130		147		47		53
	Unamortized loss on debt		79		85		51		57
	Interest rate swaps		54		44
	Accumulated cost of removal of utility plant		111		98		111		98
	AROs		72		44
	Other		8		13				1
Total noncurrent regulatory assets		$	1,253	$	1,246	$	772	$	772

Current Regulatory Liabilities:
	Generation supply charge	$	33	$	23	$	33	$	23
	Gas supply clause		4		3
	Transmission service charge		2		8		2		8
	Fuel adjustment clause		1		4
	Transmission formula rate		42		20		42		20
	Universal service rider				10				10
	Storm damage expense		1		14		1		14
	Gas line tracker		5		6
	Other		4		2		3		1
Total current regulatory liabilities		$	92	$	90	$	81	$	76

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	697	$	688
	Coal contracts (a)		69		98
	Power purchase agreement - OVEC (a)		94		100
	Net deferred tax assets		27		30
	Act 129 compliance rider		18		15	$	18	$	15
	Defined benefit plans		29		26
	Interest rate swaps		90		86
	Other		4		5
Total noncurrent regulatory liabilities		$	1,028	$	1,048	$	18	$	15

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2014		2013		2014		2013		2014		2013

Current Regulatory Assets:
	Environmental cost recovery	$	3	$	7	$	3	$	2			$	5
	Gas supply clause		20		10		20		10
	Fuel adjustment clause				2				2
	Demand side management				8				3				5
	Other		2							$	2
Total current regulatory assets		$	25	$	27	$	23	$	17	$	2	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	236	$	252	$	159	$	164	$	77	$	88
	Storm costs		83		94		45		51		38		43
	Unamortized loss on debt		28		28		18		18		10		10
	Interest rate swaps		54		44		52		44		2
	AROs		72		44		27		21		45		23
	Other		8		12		4		5		4		7
Total noncurrent regulatory assets		$	481	$	474	$	305	$	303	$	176	$	171

Current Regulatory Liabilities:
		Gas supply clause	$	4	$	3	$	4	$	3
		Fuel adjustment clause		1		4					$	1	$	4
		Gas line tracker		5		6		5		6
		Other		1		1						1		1
Total current regulatory liabilities			$	11	$	14	$	9	$	9	$	2	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	697	$	688	$	305	$	299	$	392	$	389
	Coal contracts (a)			69		98		30		43		39		55
	Power purchase agreement - OVEC (a)			94		100		65		69		29		31
	Net deferred tax assets			27		30		24		26		3		4
	Defined benefit plans			29		26						29		26
	Interest rate swaps			90		86		45		43		45		43
	Other			4		5		2		2		2		3
Total noncurrent regulatory liabilities			$	1,010	$	1,033	$	471	$	482	$	539	$	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, during the first quarter of 2014 WPD increased its existing liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenues on the Statement of Income. The total recorded liability at September 30, 2014 was $105 million, 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 and foreign exchange movements. In June 2014, WPD applied for judicial review of certain of Ofgem's decisions related to closing out the DPCR4 line loss mechanism. The court has set a hearing for November 20, 2014 to hear WPD's application for permission to seek judicial review. The primary relief sought is for Ofgem to reconsider the overall proportionality of penalties imposed on WPD. The entire process could last through the second quarter of 2015. PPL cannot predict the outcome of this matter.

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 an NGCC generating unit, Green River Unit 5, at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site. In April 2014, LG&E and KU filed a motion to hold further proceedings in abeyance to allow the companies to assess the potential impact of certain events on their future capacity needs, including the receipt of termination notices to be generally effective in 2019 from certain KU municipal wholesale customers. In August 2014, LG&E and KU submitted a motion to withdraw their request to construct the Green River NGCC and the KPSC issued an order granting that request. LG&E’s and KU’s CPCN application continues to request approval to construct the E. W. Brown solar generating facility. LG&E and KU entered into a stipulation in this proceeding agreeing to certain matters with some interveners. A hearing is scheduled to be held in November 2014, and a final order is anticipated before the end of the year. See "Federal Matters - FERC Wholesale Formula Rates" below for additional information relating to the municipal wholesale customers.

Rate Case Proceedings

On November 4, 2014, LG&E and KU announced that on November 26, 2014, they anticipate filing requests with the KPSC for increases in annual base electricity rates of approximately $30 million at LG&E and approximately $153 million at KU and an increase in annual base gas rates of approximately $14 million at LG&E. The proposed base rate increases would result in electricity rate increases of 2.7% at LG&E and 9.6% at KU and a gas rate increase of 4.2% at LG&E and would become effective in July 2015. LG&E’s and KU’s applications each include a request for authorized returns-on-equity of 10.50%. The applications are based on a forecasted test year of July 1, 2015 through June 30, 2016. LG&E and KU cannot predict the outcome of these proceedings.

Pennsylvania Activities (PPL and PPL Electric)

Storm Damage Expense Rider

In its December 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. In April 2014, the PUC issued a final order approving the SDER. The SDER will be effective January 1, 2015 and 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. On June 20, 2014, the Office of Consumer Advocate filed a petition for review of the April 2014 order with the Commonwealth Court of Pennsylvania. The case remains pending. 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 September 30, 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.

Act 129 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. In April 2014, PPL Electric filed a new DSP procurement plan with the PUC for the period June 1, 2015 through May 31, 2017. In September 2014, the parties filed with the presiding Administrative Law Judge a partial settlement resolving all but two issues in the proceeding related to the structure of the DSP, without direct financial impact on PPL Electric. The parties filed briefs on those two issues. In October 2014, a Recommended Decision was issued approving the partial settlement. This proceeding remains pending before the PUC but is not expected to have a material impact on PPL Electric.

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 conducted pilot projects and technical evaluations of its current advanced metering technology and concluded that the current technology does not meet all of the Act 129 requirements. PPL Electric recovered the cost of its evaluations 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. On June 30, 2014, PPL Electric filed its final Smart Meter Plan with the PUC. In that plan, PPL Electric proposes to replace all of its current meters with advanced meters that meet the Act 129 requirements. Full deployment of the new meters is expected to be complete by the end of 2019. The total cost of the project is estimated to be approximately $450 million. PPL Electric proposes to recover these costs through the SMR which the PUC previously has approved for recovery of such costs. The PUC assigned PPL Electric’s plan to an Administrative Law Judge for hearings and preparation of a recommended decision. PPL Electric cannot predict the outcome of this proceeding.

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. In August 2014, the presiding Administrative Law Judge issued a recommended decision which would not have a significant impact on PPL Electric. This matter 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. In September 2014, the parties filed a Joint Offer of Settlement with the FERC resolving all issues in the pending challenges, and including refunds of certain insignificant amounts to the municipalities. The settlement judge certified the uncontested settlement to the FERC with a recommendation that it be approved.

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 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, 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 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. If approved, the settlement agreement will resolve the rate case with respect to these two municipalities, including an authorized return on equity of 10% or the return on equity awarded to other parties in this case, whichever is lower. Also in July 2014, KU made a contractually required filing with the FERC that addressed certain rate recovery matters affecting the nine terminating municipalities during the remaining term of their contracts. KU and the terminating municipalities continue settlement discussions in this proceeding. KU cannot currently predict the outcome of its FERC applications regarding its wholesale power agreements with the municipalities.