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,
		2013		2012		2013		2012

Current Regulatory Assets:
	ECR	$	7
	Gas supply clause		13	$	11
	Fuel adjustment clause				6
	Other		11		2	$	2
Total current regulatory assets		$	31	$	19	$	2

Noncurrent Regulatory Assets:
	Defined benefit plans	$	683	$	730	$	345	$	362
	Taxes recoverable through future rates		302		293		302		293
	Storm costs		152		168		55		59
	Unamortized loss on debt		88		96		58		65
	Interest rate swaps		49		67
	Accumulated cost of removal of utility plant		95		71		95		71
	AROs		37		26
	Other		17		32		2		3
Total noncurrent regulatory assets		$	1,423	$	1,483	$	857	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	21	$	27	$	21	$	27
	ECR				4
	Gas supply clause		2		4
	Transmission service charge		9		6		9		6
	Transmission formula rate		9				9
	Universal service rider		11		17		11		17
	Gas line tracker		6
	Other		10		3		1		2
Total current regulatory liabilities		$	68	$	61	$	51	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	690	$	679
	Coal contracts (a)		108		141
	Power purchase agreement - OVEC (a)		102		108
	Net deferred tax assets		32		34
	Act 129 compliance rider		14		8	$	14	$	8
	Defined benefit plans		18		17
	Interest rate swaps		84		14
	Other		6		9
Total noncurrent regulatory liabilities		$	1,054	$	1,010	$	14	$	8

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2013		2012		2013		2012		2013		2012

Current Regulatory Assets:
	ECR	$	7			$	2			$	5
	Gas supply clause		13	$	11		13	$	11
	Fuel adjustment clause				6				6
	Other		9		2		4		2		5
Total current regulatory assets		$	29	$	19	$	19	$	19	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	338	$	368	$	212	$	232	$	126	$	136
	Storm costs		97		109		53		59		44		50
	Unamortized loss on debt		30		31		19		20		11		11
	Interest rate swaps		49		67		49		67
	AROs		37		26		20		15		17		11
	Other		15		29		6		7		9		22
Total noncurrent regulatory assets		$	566	$	630	$	359	$	400	$	207	$	230

Current Regulatory Liabilities:
		ECR			$	4							$	4
		Gas supply clause	$	2		4	$	2	$	4
		Gas line tracker		6				6
		Other		9		1		3			$	6		1
Total current regulatory liabilities			$	17	$	9	$	11	$	4	$	6	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	690	$	679	$	300	$	297	$	390	$	382
	Coal contracts (a)			108		141		47		61		61		80
	Power purchase agreement - OVEC (a)			102		108		71		75		31		33
	Net deferred tax assets			32		34		26		28		6		6
	Defined benefit plans			18		17						18		17
	Interest rate swaps			84		14		42		7		42		7
	Other			6		9		3		3		3		6
Total noncurrent regulatory liabilities			$	1,040	$	1,002	$	489	$	471	$	551	$	531

(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

Kentucky Activities (PPL and Kentucky Registrants)

Rate Case Proceedings

In December 2012, the KPSC approved a rate case settlement agreement providing for increases in annual base electricity rates of $34 million for LG&E and $51 million for KU and an increase in annual base gas rates of $15 million for LG&E using a 10.25% return on equity. The approved rates became effective January 1, 2013.

Pennsylvania Activities (PPL and PPL Electric)

Rate Case Proceeding

In December 2012, the PUC approved a total distribution revenue increase of about $71 million for PPL Electric, using a 10.40% return on equity. The approved rates became effective January 1, 2013.

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). PPL Electric filed its proposed SDER on March 28, 2013, including requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy, which the PUC previously approved for deferral. PPL Electric proposed that the SDER become effective January 1, 2013 for storm costs incurred in 2013, with those costs and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. Several parties filed comments opposing the SDER. PPL Electric and several other parties filed reply comments in May 2013. In October 2013, the PUC adopted an Order requesting submission of additional comments and reply comments on PPL Electric's proposal. This matter remains pending before the PUC.

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 1 EE&C Plan ending May 31, 2013.

Act 129 requires 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%. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. PPL Electric believes it has met the May 2011 requirement and will determine if it met the May 2013 peak demand reduction and energy reduction targets after it completes the final program evaluation in the fourth quarter of 2013. PPL Electric does not expect the PUC to formally determine compliance for either the 2011 or 2013 requirements before the first quarter of 2014.

Act 129 requires the PUC 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 filed its Phase II EE&C Plan with the PUC on November 15, 2012 and, in March 2013, the PUC approved PPL Electric's Phase II EE&C Plan with minor modifications. PPL Electric filed a Revised Phase II EE&C Plan on May 13, 2013 pursuant to the PUC's March Order. On July 11, 2013, the PUC issued an Order approving PPL Electric's Revised Phase II EE&C Plan. PPL Electric began its Phase II Plan implementation on June 1, 2013.

Act 129 also requires Default Service Providers (DSP) to provide electric 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.

The PUC has approved PPL Electric's DSP procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric has concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In January 2013, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues. In February 2013, PPL Electric filed a revised Default Service Supply Master Agreement and a revised Request for Proposals Process and Rules which the PUC approved. PPL Electric filed revised retail competition initiatives and a revised plan consistent with the PUC's January order, and in May 2013, the PUC approved PPL Electric's most recent filing with minor changes. PPL Electric began implementing its revised plan on June 1, 2013. See Note 10 for additional information.

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 will become effective January 1, 2014. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for phase one of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. From December 2011 through the end of 2012, the PUC issued several orders and other pronouncements related to the investigation. A final implementation order was issued in February 2013, and the PUC created several working groups to address continuing competitive issues. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.

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. The PUC approved the LTIIP on January 10, 2013 and, on January 15, 2013, PPL Electric filed a petition requesting permission to establish a DSIC. Several parties filed responses to PPL Electric's petition. 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 specific issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. The Judge's recommended decision is expected in early 2014. The case remains pending before the PUC.

Federal Matters

FERC Audit Proceedings (All Registrants except PPL Energy Supply)

In November 2011, the FERC commenced an audit of PPL and its subsidiaries, including an audit of the FERC transmission formula rate mechanisms at PPL Electric, LG&E and KU beginning in April 2012. The audit identified several matters related to separate aspects of formula rate mechanics at PPL Electric, LG&E and KU. As previously reported, among the audit matters related to PPL Electric was the determination that PPL Electric had not obtained a waiver of the equity method accounting requirement with respect to its wholly owned subsidiary, PPL Receivables Corporation, which was formed in 2004 to purchase eligible accounts receivable and unbilled revenue from PPL Electric to collateralize commercial paper issuances and reduce borrowing costs. PPL, PPL Electric, LKE, LG&E and KU currently believe that the total amount of refunds, if any, that may be required with respect to the formula rate and all other issues identified during the course of the audit will not be material to any of these Registrants. PPL, PPL Electric, LKE, LG&E and KU, however, cannot predict the ultimate outcome of these matters.

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 No. 1, filed under the FERC's Uniform System of Accounts. PPL Electric has initiated separate formula rate Annual Updates for each of the years 2010-2013. The 2010, 2011, and 2012 updates were subsequently challenged by a group of municipal customers, which challenges PPL Electric has opposed. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric filed a request for rehearing of the February Order which remains pending before the FERC. PPL Electric and the group of municipal customers have exchanged confidential settlement proposals and PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. On July 12, 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss incentive/penalty. Subsequent to the July 2013 decision paper, WPD received additional information from Ofgem and as a result revised the estimated potential loss exposure to be in the range of $93 million to $226 million as of September 30, 2013. On October 21, 2013, Ofgem issued a further consultation paper requesting additional information. During the three and nine months ended September 30, 2013, WPD recorded $21 million and $45 million increases to the liability with reductions to "Utility" revenue on the Statement of Income. At September 30, 2013, the liability was $93 million compared with $94 million at December 31, 2012. Other changes to this line loss liability included reductions of $41 million resulting from refunds being included in tariffs and foreign exchange movements during the nine months ended September 30, 2013. PPL cannot predict the outcome of this matter.

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,
		2013		2012		2013		2012

Current Regulatory Assets:
	ECR	$	7
	Gas supply clause		13	$	11
	Fuel adjustment clause				6
	Other		11		2	$	2
Total current regulatory assets		$	31	$	19	$	2

Noncurrent Regulatory Assets:
	Defined benefit plans	$	683	$	730	$	345	$	362
	Taxes recoverable through future rates		302		293		302		293
	Storm costs		152		168		55		59
	Unamortized loss on debt		88		96		58		65
	Interest rate swaps		49		67
	Accumulated cost of removal of utility plant		95		71		95		71
	AROs		37		26
	Other		17		32		2		3
Total noncurrent regulatory assets		$	1,423	$	1,483	$	857	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	21	$	27	$	21	$	27
	ECR				4
	Gas supply clause		2		4
	Transmission service charge		9		6		9		6
	Transmission formula rate		9				9
	Universal service rider		11		17		11		17
	Gas line tracker		6
	Other		10		3		1		2
Total current regulatory liabilities		$	68	$	61	$	51	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	690	$	679
	Coal contracts (a)		108		141
	Power purchase agreement - OVEC (a)		102		108
	Net deferred tax assets		32		34
	Act 129 compliance rider		14		8	$	14	$	8
	Defined benefit plans		18		17
	Interest rate swaps		84		14
	Other		6		9
Total noncurrent regulatory liabilities		$	1,054	$	1,010	$	14	$	8

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2013		2012		2013		2012		2013		2012

Current Regulatory Assets:
	ECR	$	7			$	2			$	5
	Gas supply clause		13	$	11		13	$	11
	Fuel adjustment clause				6				6
	Other		9		2		4		2		5
Total current regulatory assets		$	29	$	19	$	19	$	19	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	338	$	368	$	212	$	232	$	126	$	136
	Storm costs		97		109		53		59		44		50
	Unamortized loss on debt		30		31		19		20		11		11
	Interest rate swaps		49		67		49		67
	AROs		37		26		20		15		17		11
	Other		15		29		6		7		9		22
Total noncurrent regulatory assets		$	566	$	630	$	359	$	400	$	207	$	230

Current Regulatory Liabilities:
		ECR			$	4							$	4
		Gas supply clause	$	2		4	$	2	$	4
		Gas line tracker		6				6
		Other		9		1		3			$	6		1
Total current regulatory liabilities			$	17	$	9	$	11	$	4	$	6	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	690	$	679	$	300	$	297	$	390	$	382
	Coal contracts (a)			108		141		47		61		61		80
	Power purchase agreement - OVEC (a)			102		108		71		75		31		33
	Net deferred tax assets			32		34		26		28		6		6
	Defined benefit plans			18		17						18		17
	Interest rate swaps			84		14		42		7		42		7
	Other			6		9		3		3		3		6
Total noncurrent regulatory liabilities			$	1,040	$	1,002	$	489	$	471	$	551	$	531

(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

Kentucky Activities (PPL and Kentucky Registrants)

Rate Case Proceedings

In December 2012, the KPSC approved a rate case settlement agreement providing for increases in annual base electricity rates of $34 million for LG&E and $51 million for KU and an increase in annual base gas rates of $15 million for LG&E using a 10.25% return on equity. The approved rates became effective January 1, 2013.

Pennsylvania Activities (PPL and PPL Electric)

Rate Case Proceeding

In December 2012, the PUC approved a total distribution revenue increase of about $71 million for PPL Electric, using a 10.40% return on equity. The approved rates became effective January 1, 2013.

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). PPL Electric filed its proposed SDER on March 28, 2013, including requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy, which the PUC previously approved for deferral. PPL Electric proposed that the SDER become effective January 1, 2013 for storm costs incurred in 2013, with those costs and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. Several parties filed comments opposing the SDER. PPL Electric and several other parties filed reply comments in May 2013. In October 2013, the PUC adopted an Order requesting submission of additional comments and reply comments on PPL Electric's proposal. This matter remains pending before the PUC.

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 1 EE&C Plan ending May 31, 2013.

Act 129 requires 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%. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. PPL Electric believes it has met the May 2011 requirement and will determine if it met the May 2013 peak demand reduction and energy reduction targets after it completes the final program evaluation in the fourth quarter of 2013. PPL Electric does not expect the PUC to formally determine compliance for either the 2011 or 2013 requirements before the first quarter of 2014.

Act 129 requires the PUC 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 filed its Phase II EE&C Plan with the PUC on November 15, 2012 and, in March 2013, the PUC approved PPL Electric's Phase II EE&C Plan with minor modifications. PPL Electric filed a Revised Phase II EE&C Plan on May 13, 2013 pursuant to the PUC's March Order. On July 11, 2013, the PUC issued an Order approving PPL Electric's Revised Phase II EE&C Plan. PPL Electric began its Phase II Plan implementation on June 1, 2013.

Act 129 also requires Default Service Providers (DSP) to provide electric 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.

The PUC has approved PPL Electric's DSP procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric has concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In January 2013, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues. In February 2013, PPL Electric filed a revised Default Service Supply Master Agreement and a revised Request for Proposals Process and Rules which the PUC approved. PPL Electric filed revised retail competition initiatives and a revised plan consistent with the PUC's January order, and in May 2013, the PUC approved PPL Electric's most recent filing with minor changes. PPL Electric began implementing its revised plan on June 1, 2013. See Note 10 for additional information.

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 will become effective January 1, 2014. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for phase one of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. From December 2011 through the end of 2012, the PUC issued several orders and other pronouncements related to the investigation. A final implementation order was issued in February 2013, and the PUC created several working groups to address continuing competitive issues. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.

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. The PUC approved the LTIIP on January 10, 2013 and, on January 15, 2013, PPL Electric filed a petition requesting permission to establish a DSIC. Several parties filed responses to PPL Electric's petition. 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 specific issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. The Judge's recommended decision is expected in early 2014. The case remains pending before the PUC.

Federal Matters

FERC Audit Proceedings (All Registrants except PPL Energy Supply)

In November 2011, the FERC commenced an audit of PPL and its subsidiaries, including an audit of the FERC transmission formula rate mechanisms at PPL Electric, LG&E and KU beginning in April 2012. The audit identified several matters related to separate aspects of formula rate mechanics at PPL Electric, LG&E and KU. As previously reported, among the audit matters related to PPL Electric was the determination that PPL Electric had not obtained a waiver of the equity method accounting requirement with respect to its wholly owned subsidiary, PPL Receivables Corporation, which was formed in 2004 to purchase eligible accounts receivable and unbilled revenue from PPL Electric to collateralize commercial paper issuances and reduce borrowing costs. PPL, PPL Electric, LKE, LG&E and KU currently believe that the total amount of refunds, if any, that may be required with respect to the formula rate and all other issues identified during the course of the audit will not be material to any of these Registrants. PPL, PPL Electric, LKE, LG&E and KU, however, cannot predict the ultimate outcome of these matters.

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 No. 1, filed under the FERC's Uniform System of Accounts. PPL Electric has initiated separate formula rate Annual Updates for each of the years 2010-2013. The 2010, 2011, and 2012 updates were subsequently challenged by a group of municipal customers, which challenges PPL Electric has opposed. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric filed a request for rehearing of the February Order which remains pending before the FERC. PPL Electric and the group of municipal customers have exchanged confidential settlement proposals and PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. On July 12, 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss incentive/penalty. Subsequent to the July 2013 decision paper, WPD received additional information from Ofgem and as a result revised the estimated potential loss exposure to be in the range of $93 million to $226 million as of September 30, 2013. On October 21, 2013, Ofgem issued a further consultation paper requesting additional information. During the three and nine months ended September 30, 2013, WPD recorded $21 million and $45 million increases to the liability with reductions to "Utility" revenue on the Statement of Income. At September 30, 2013, the liability was $93 million compared with $94 million at December 31, 2012. Other changes to this line loss liability included reductions of $41 million resulting from refunds being included in tariffs and foreign exchange movements during the nine months ended September 30, 2013. PPL cannot predict the outcome of this matter.

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,
		2013		2012		2013		2012

Current Regulatory Assets:
	ECR	$	7
	Gas supply clause		13	$	11
	Fuel adjustment clause				6
	Other		11		2	$	2
Total current regulatory assets		$	31	$	19	$	2

Noncurrent Regulatory Assets:
	Defined benefit plans	$	683	$	730	$	345	$	362
	Taxes recoverable through future rates		302		293		302		293
	Storm costs		152		168		55		59
	Unamortized loss on debt		88		96		58		65
	Interest rate swaps		49		67
	Accumulated cost of removal of utility plant		95		71		95		71
	AROs		37		26
	Other		17		32		2		3
Total noncurrent regulatory assets		$	1,423	$	1,483	$	857	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	21	$	27	$	21	$	27
	ECR				4
	Gas supply clause		2		4
	Transmission service charge		9		6		9		6
	Transmission formula rate		9				9
	Universal service rider		11		17		11		17
	Gas line tracker		6
	Other		10		3		1		2
Total current regulatory liabilities		$	68	$	61	$	51	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	690	$	679
	Coal contracts (a)		108		141
	Power purchase agreement - OVEC (a)		102		108
	Net deferred tax assets		32		34
	Act 129 compliance rider		14		8	$	14	$	8
	Defined benefit plans		18		17
	Interest rate swaps		84		14
	Other		6		9
Total noncurrent regulatory liabilities		$	1,054	$	1,010	$	14	$	8

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2013		2012		2013		2012		2013		2012

Current Regulatory Assets:
	ECR	$	7			$	2			$	5
	Gas supply clause		13	$	11		13	$	11
	Fuel adjustment clause				6				6
	Other		9		2		4		2		5
Total current regulatory assets		$	29	$	19	$	19	$	19	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	338	$	368	$	212	$	232	$	126	$	136
	Storm costs		97		109		53		59		44		50
	Unamortized loss on debt		30		31		19		20		11		11
	Interest rate swaps		49		67		49		67
	AROs		37		26		20		15		17		11
	Other		15		29		6		7		9		22
Total noncurrent regulatory assets		$	566	$	630	$	359	$	400	$	207	$	230

Current Regulatory Liabilities:
		ECR			$	4							$	4
		Gas supply clause	$	2		4	$	2	$	4
		Gas line tracker		6				6
		Other		9		1		3			$	6		1
Total current regulatory liabilities			$	17	$	9	$	11	$	4	$	6	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	690	$	679	$	300	$	297	$	390	$	382
	Coal contracts (a)			108		141		47		61		61		80
	Power purchase agreement - OVEC (a)			102		108		71		75		31		33
	Net deferred tax assets			32		34		26		28		6		6
	Defined benefit plans			18		17						18		17
	Interest rate swaps			84		14		42		7		42		7
	Other			6		9		3		3		3		6
Total noncurrent regulatory liabilities			$	1,040	$	1,002	$	489	$	471	$	551	$	531

(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

Kentucky Activities (PPL and Kentucky Registrants)

Rate Case Proceedings

In December 2012, the KPSC approved a rate case settlement agreement providing for increases in annual base electricity rates of $34 million for LG&E and $51 million for KU and an increase in annual base gas rates of $15 million for LG&E using a 10.25% return on equity. The approved rates became effective January 1, 2013.

Pennsylvania Activities (PPL and PPL Electric)

Rate Case Proceeding

In December 2012, the PUC approved a total distribution revenue increase of about $71 million for PPL Electric, using a 10.40% return on equity. The approved rates became effective January 1, 2013.

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). PPL Electric filed its proposed SDER on March 28, 2013, including requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy, which the PUC previously approved for deferral. PPL Electric proposed that the SDER become effective January 1, 2013 for storm costs incurred in 2013, with those costs and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. Several parties filed comments opposing the SDER. PPL Electric and several other parties filed reply comments in May 2013. In October 2013, the PUC adopted an Order requesting submission of additional comments and reply comments on PPL Electric's proposal. This matter remains pending before the PUC.

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 1 EE&C Plan ending May 31, 2013.

Act 129 requires 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%. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. PPL Electric believes it has met the May 2011 requirement and will determine if it met the May 2013 peak demand reduction and energy reduction targets after it completes the final program evaluation in the fourth quarter of 2013. PPL Electric does not expect the PUC to formally determine compliance for either the 2011 or 2013 requirements before the first quarter of 2014.

Act 129 requires the PUC 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 filed its Phase II EE&C Plan with the PUC on November 15, 2012 and, in March 2013, the PUC approved PPL Electric's Phase II EE&C Plan with minor modifications. PPL Electric filed a Revised Phase II EE&C Plan on May 13, 2013 pursuant to the PUC's March Order. On July 11, 2013, the PUC issued an Order approving PPL Electric's Revised Phase II EE&C Plan. PPL Electric began its Phase II Plan implementation on June 1, 2013.

Act 129 also requires Default Service Providers (DSP) to provide electric 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.

The PUC has approved PPL Electric's DSP procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric has concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In January 2013, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues. In February 2013, PPL Electric filed a revised Default Service Supply Master Agreement and a revised Request for Proposals Process and Rules which the PUC approved. PPL Electric filed revised retail competition initiatives and a revised plan consistent with the PUC's January order, and in May 2013, the PUC approved PPL Electric's most recent filing with minor changes. PPL Electric began implementing its revised plan on June 1, 2013. See Note 10 for additional information.

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 will become effective January 1, 2014. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for phase one of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. From December 2011 through the end of 2012, the PUC issued several orders and other pronouncements related to the investigation. A final implementation order was issued in February 2013, and the PUC created several working groups to address continuing competitive issues. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.

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. The PUC approved the LTIIP on January 10, 2013 and, on January 15, 2013, PPL Electric filed a petition requesting permission to establish a DSIC. Several parties filed responses to PPL Electric's petition. 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 specific issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. The Judge's recommended decision is expected in early 2014. The case remains pending before the PUC.

Federal Matters

FERC Audit Proceedings (All Registrants except PPL Energy Supply)

In November 2011, the FERC commenced an audit of PPL and its subsidiaries, including an audit of the FERC transmission formula rate mechanisms at PPL Electric, LG&E and KU beginning in April 2012. The audit identified several matters related to separate aspects of formula rate mechanics at PPL Electric, LG&E and KU. As previously reported, among the audit matters related to PPL Electric was the determination that PPL Electric had not obtained a waiver of the equity method accounting requirement with respect to its wholly owned subsidiary, PPL Receivables Corporation, which was formed in 2004 to purchase eligible accounts receivable and unbilled revenue from PPL Electric to collateralize commercial paper issuances and reduce borrowing costs. PPL, PPL Electric, LKE, LG&E and KU currently believe that the total amount of refunds, if any, that may be required with respect to the formula rate and all other issues identified during the course of the audit will not be material to any of these Registrants. PPL, PPL Electric, LKE, LG&E and KU, however, cannot predict the ultimate outcome of these matters.

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 No. 1, filed under the FERC's Uniform System of Accounts. PPL Electric has initiated separate formula rate Annual Updates for each of the years 2010-2013. The 2010, 2011, and 2012 updates were subsequently challenged by a group of municipal customers, which challenges PPL Electric has opposed. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric filed a request for rehearing of the February Order which remains pending before the FERC. PPL Electric and the group of municipal customers have exchanged confidential settlement proposals and PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. On July 12, 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss incentive/penalty. Subsequent to the July 2013 decision paper, WPD received additional information from Ofgem and as a result revised the estimated potential loss exposure to be in the range of $93 million to $226 million as of September 30, 2013. On October 21, 2013, Ofgem issued a further consultation paper requesting additional information. During the three and nine months ended September 30, 2013, WPD recorded $21 million and $45 million increases to the liability with reductions to "Utility" revenue on the Statement of Income. At September 30, 2013, the liability was $93 million compared with $94 million at December 31, 2012. Other changes to this line loss liability included reductions of $41 million resulting from refunds being included in tariffs and foreign exchange movements during the nine months ended September 30, 2013. PPL cannot predict the outcome of this matter.