6. Utility Rate Regulation

(PPL, PPL Electric, LKE, LG&E and KU)

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

		PPL				PPL Electric
		June 30,		December 31,		June 30,		December 31,
		2013		2012		2013		2012

Current Regulatory Assets:
	Transmission formula rate	$	5			$	5
	ECR		7
	Gas supply clause		14	$	11
	Fuel adjustment clause		3		6
	Other		5		2
Total current regulatory assets		$	34	$	19	$	5

Noncurrent Regulatory Assets:
	Defined benefit plans	$	700	$	730	$	351	$	362
	Taxes recoverable through future rates		298		293		298		293
	Storm costs		157		168		56		59
	Unamortized loss on debt		90		96		60		65
	Interest rate swaps		51		67
	Accumulated cost of removal of utility plant		92		71		92		71
	AROs		34		26
	Other		21		32		5		3
Total noncurrent regulatory assets		$	1,443	$	1,483	$	862	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	24	$	27	$	24	$	27
	ECR				4
	Gas supply clause				4
	Transmission service charge		11		6		11		6
	Universal service rider		11		17		11		17
	Other		8		3		2		2
Total current regulatory liabilities		$	54	$	61	$	48	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	689	$	679
	Coal contracts (a)		119		141
	Power purchase agreement - OVEC (a)		104		108
	Net deferred tax assets		32		34
	Act 129 compliance rider		13		8	$	13	$	8
	Defined benefit plans		18		17
	Interest rate swaps		72		14
	Other		5		9
Total noncurrent regulatory liabilities		$	1,052	$	1,010	$	13	$	8

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

Current Regulatory Assets:
	ECR	$	7			$	2			$	5
	Gas supply clause		14	$	11		14	$	11
	Fuel adjustment clause		3		6		3		6
	Other		5		2		2		2		3
Total current regulatory assets		$	29	$	19	$	21	$	19	$	8

Noncurrent Regulatory Assets:
	Defined benefit plans	$	349	$	368	$	219	$	232	$	130	$	136
	Storm costs		101		109		55		59		46		50
	Unamortized loss on debt		30		31		19		20		11		11
	Interest rate swaps		51		67		51		67
	AROs		34		26		19		15		15		11
	Other		16		29		6		7		10		22
Total noncurrent regulatory assets		$	581	$	630	$	369	$	400	$	212	$	230

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

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	689	$	679	$	300	$	297	$	389	$	382
	Coal contracts (a)			119		141		52		61		67		80
	Power purchase agreement - OVEC (a)			104		108		72		75		32		33
	Net deferred tax assets			32		34		26		28		6		6
	Defined benefit plans			18		17						18		17
	Interest rate swaps			72		14		36		7		36		7
	Other			5		9		2		3		3		6
Total noncurrent regulatory liabilities			$	1,039	$	1,002	$	488	$	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, LKE, LG&E and KU)

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, using a 10.4% return on equity. The approved rates became effective January 1, 2013.

Storm Damage Expense Rider

In its December 28, 2012 final rate case proceeding order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER) within 90 days following the order. PPL Electric filed its proposed SDER with the PUC 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. 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 May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. Although PPL Electric believes it has met the May 2011 requirement, the PUC is not expected to formally determine compliance for any EDC before the first quarter of 2014. 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 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.

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 June 1, 2009 through May 31, 2010 baseline year. 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 competitive 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 its January 24, 2013 final order, 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. In an order entered on May 23, 2013, the PUC approved PPL Electric's most recent filing with minor changes and 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 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013. In August 2013, PPL Electric will file its annual Smart Meter report and revised SMR charges to 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. A prehearing conference has been held and a litigation schedule set with evidentiary hearings scheduled for the end of October 2013. The case remains pending before the PUC.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

PPL Electric must follow the FERC's Uniform System of Accounts (USOA), which requires subsidiaries to be presented, for FERC reporting purposes, using the equity method of accounting unless a waiver has been granted. The FERC has granted waivers of this requirement to other utilities when alternative accounting would more accurately present the integrated operations of a utility and its subsidiaries. In March 2013, as part of a routine FERC audit of PPL and its subsidiaries, PPL Electric determined that it never obtained a waiver of the equity method accounting requirement for PPL Receivables Corporation (PPL Receivables). PPL Receivables is a wholly owned subsidiary of PPL Electric, formed in 2004 to purchase eligible accounts receivable and unbilled revenue of PPL Electric to collateralize commercial paper issuances and reduce borrowing costs. In March 2013, PPL Electric filed a request for waiver with the FERC that, if approved, would allow it to continue to consolidate the results of PPL Receivables with the results of PPL Electric, as it has done since 2004. Although PPL Electric may ultimately be successful in obtaining the waiver, the FERC may require PPL Electric to re-issue one or more of its prior FERC Form No. 1 filings. If re-issuance of FERC Form No. 1 filings were required by the FERC, PPL Electric's revenue requirement calculated under the formula rate could be negatively impacted. The impact, if any, is not known at this time but could range between $0 and $40 million, pre-tax. PPL Electric cannot predict the outcome of the waiver or audit proceedings, which remain pending before the FERC.

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 USOA. 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. In April 2013, Ofgem stated that their expectation was to issue a decision in the second half of 2013. On July 12, 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss incentive/penalty. Based on one element of the decision paper, WPD has concluded that certain data, which had previously served to reduce the liability calculation, could not be included. Additional information in the decision paper has increased the level of uncertainty regarding the ultimate settlement of this liability. WPD currently estimates the potential loss exposure to be in the range of $97 million to $251 million. As a result, during the three and six months ended June 30, 2013, WPD recorded a $24 million increase to the liability with a reduction to "Utility" revenue on the Statement of Income, increasing the liability to $97 million at June 30, 2013 compared with $94 million at December 31, 2012. Other changes to this line loss liability included reductions of $16 million resulting from the refund being included in tariffs starting in April 2013 and foreign exchange movement during the six months ended June 30, 2013. PPL cannot predict the outcome of this matter.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

(PPL, PPL Electric, LKE, LG&E and KU)

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

		PPL				PPL Electric
		June 30,		December 31,		June 30,		December 31,
		2013		2012		2013		2012

Current Regulatory Assets:
	Transmission formula rate	$	5			$	5
	ECR		7
	Gas supply clause		14	$	11
	Fuel adjustment clause		3		6
	Other		5		2
Total current regulatory assets		$	34	$	19	$	5

Noncurrent Regulatory Assets:
	Defined benefit plans	$	700	$	730	$	351	$	362
	Taxes recoverable through future rates		298		293		298		293
	Storm costs		157		168		56		59
	Unamortized loss on debt		90		96		60		65
	Interest rate swaps		51		67
	Accumulated cost of removal of utility plant		92		71		92		71
	AROs		34		26
	Other		21		32		5		3
Total noncurrent regulatory assets		$	1,443	$	1,483	$	862	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	24	$	27	$	24	$	27
	ECR				4
	Gas supply clause				4
	Transmission service charge		11		6		11		6
	Universal service rider		11		17		11		17
	Other		8		3		2		2
Total current regulatory liabilities		$	54	$	61	$	48	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	689	$	679
	Coal contracts (a)		119		141
	Power purchase agreement - OVEC (a)		104		108
	Net deferred tax assets		32		34
	Act 129 compliance rider		13		8	$	13	$	8
	Defined benefit plans		18		17
	Interest rate swaps		72		14
	Other		5		9
Total noncurrent regulatory liabilities		$	1,052	$	1,010	$	13	$	8

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

Current Regulatory Assets:
	ECR	$	7			$	2			$	5
	Gas supply clause		14	$	11		14	$	11
	Fuel adjustment clause		3		6		3		6
	Other		5		2		2		2		3
Total current regulatory assets		$	29	$	19	$	21	$	19	$	8

Noncurrent Regulatory Assets:
	Defined benefit plans	$	349	$	368	$	219	$	232	$	130	$	136
	Storm costs		101		109		55		59		46		50
	Unamortized loss on debt		30		31		19		20		11		11
	Interest rate swaps		51		67		51		67
	AROs		34		26		19		15		15		11
	Other		16		29		6		7		10		22
Total noncurrent regulatory assets		$	581	$	630	$	369	$	400	$	212	$	230

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

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	689	$	679	$	300	$	297	$	389	$	382
	Coal contracts (a)			119		141		52		61		67		80
	Power purchase agreement - OVEC (a)			104		108		72		75		32		33
	Net deferred tax assets			32		34		26		28		6		6
	Defined benefit plans			18		17						18		17
	Interest rate swaps			72		14		36		7		36		7
	Other			5		9		2		3		3		6
Total noncurrent regulatory liabilities			$	1,039	$	1,002	$	488	$	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, LKE, LG&E and KU)

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, using a 10.4% return on equity. The approved rates became effective January 1, 2013.

Storm Damage Expense Rider

In its December 28, 2012 final rate case proceeding order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER) within 90 days following the order. PPL Electric filed its proposed SDER with the PUC 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. 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 May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. Although PPL Electric believes it has met the May 2011 requirement, the PUC is not expected to formally determine compliance for any EDC before the first quarter of 2014. 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 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.

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 June 1, 2009 through May 31, 2010 baseline year. 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 competitive 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 its January 24, 2013 final order, 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. In an order entered on May 23, 2013, the PUC approved PPL Electric's most recent filing with minor changes and 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 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013. In August 2013, PPL Electric will file its annual Smart Meter report and revised SMR charges to 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. A prehearing conference has been held and a litigation schedule set with evidentiary hearings scheduled for the end of October 2013. The case remains pending before the PUC.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

PPL Electric must follow the FERC's Uniform System of Accounts (USOA), which requires subsidiaries to be presented, for FERC reporting purposes, using the equity method of accounting unless a waiver has been granted. The FERC has granted waivers of this requirement to other utilities when alternative accounting would more accurately present the integrated operations of a utility and its subsidiaries. In March 2013, as part of a routine FERC audit of PPL and its subsidiaries, PPL Electric determined that it never obtained a waiver of the equity method accounting requirement for PPL Receivables Corporation (PPL Receivables). PPL Receivables is a wholly owned subsidiary of PPL Electric, formed in 2004 to purchase eligible accounts receivable and unbilled revenue of PPL Electric to collateralize commercial paper issuances and reduce borrowing costs. In March 2013, PPL Electric filed a request for waiver with the FERC that, if approved, would allow it to continue to consolidate the results of PPL Receivables with the results of PPL Electric, as it has done since 2004. Although PPL Electric may ultimately be successful in obtaining the waiver, the FERC may require PPL Electric to re-issue one or more of its prior FERC Form No. 1 filings. If re-issuance of FERC Form No. 1 filings were required by the FERC, PPL Electric's revenue requirement calculated under the formula rate could be negatively impacted. The impact, if any, is not known at this time but could range between $0 and $40 million, pre-tax. PPL Electric cannot predict the outcome of the waiver or audit proceedings, which remain pending before the FERC.

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 USOA. 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. In April 2013, Ofgem stated that their expectation was to issue a decision in the second half of 2013. On July 12, 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss incentive/penalty. Based on one element of the decision paper, WPD has concluded that certain data, which had previously served to reduce the liability calculation, could not be included. Additional information in the decision paper has increased the level of uncertainty regarding the ultimate settlement of this liability. WPD currently estimates the potential loss exposure to be in the range of $97 million to $251 million. As a result, during the three and six months ended June 30, 2013, WPD recorded a $24 million increase to the liability with a reduction to "Utility" revenue on the Statement of Income, increasing the liability to $97 million at June 30, 2013 compared with $94 million at December 31, 2012. Other changes to this line loss liability included reductions of $16 million resulting from the refund being included in tariffs starting in April 2013 and foreign exchange movement during the six months ended June 30, 2013. PPL cannot predict the outcome of this matter.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

(PPL, PPL Electric, LKE, LG&E and KU)

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

		PPL				PPL Electric
		June 30,		December 31,		June 30,		December 31,
		2013		2012		2013		2012

Current Regulatory Assets:
	Transmission formula rate	$	5			$	5
	ECR		7
	Gas supply clause		14	$	11
	Fuel adjustment clause		3		6
	Other		5		2
Total current regulatory assets		$	34	$	19	$	5

Noncurrent Regulatory Assets:
	Defined benefit plans	$	700	$	730	$	351	$	362
	Taxes recoverable through future rates		298		293		298		293
	Storm costs		157		168		56		59
	Unamortized loss on debt		90		96		60		65
	Interest rate swaps		51		67
	Accumulated cost of removal of utility plant		92		71		92		71
	AROs		34		26
	Other		21		32		5		3
Total noncurrent regulatory assets		$	1,443	$	1,483	$	862	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	24	$	27	$	24	$	27
	ECR				4
	Gas supply clause				4
	Transmission service charge		11		6		11		6
	Universal service rider		11		17		11		17
	Other		8		3		2		2
Total current regulatory liabilities		$	54	$	61	$	48	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	689	$	679
	Coal contracts (a)		119		141
	Power purchase agreement - OVEC (a)		104		108
	Net deferred tax assets		32		34
	Act 129 compliance rider		13		8	$	13	$	8
	Defined benefit plans		18		17
	Interest rate swaps		72		14
	Other		5		9
Total noncurrent regulatory liabilities		$	1,052	$	1,010	$	13	$	8

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

Current Regulatory Assets:
	ECR	$	7			$	2			$	5
	Gas supply clause		14	$	11		14	$	11
	Fuel adjustment clause		3		6		3		6
	Other		5		2		2		2		3
Total current regulatory assets		$	29	$	19	$	21	$	19	$	8

Noncurrent Regulatory Assets:
	Defined benefit plans	$	349	$	368	$	219	$	232	$	130	$	136
	Storm costs		101		109		55		59		46		50
	Unamortized loss on debt		30		31		19		20		11		11
	Interest rate swaps		51		67		51		67
	AROs		34		26		19		15		15		11
	Other		16		29		6		7		10		22
Total noncurrent regulatory assets		$	581	$	630	$	369	$	400	$	212	$	230

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

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	689	$	679	$	300	$	297	$	389	$	382
	Coal contracts (a)			119		141		52		61		67		80
	Power purchase agreement - OVEC (a)			104		108		72		75		32		33
	Net deferred tax assets			32		34		26		28		6		6
	Defined benefit plans			18		17						18		17
	Interest rate swaps			72		14		36		7		36		7
	Other			5		9		2		3		3		6
Total noncurrent regulatory liabilities			$	1,039	$	1,002	$	488	$	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, LKE, LG&E and KU)

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, using a 10.4% return on equity. The approved rates became effective January 1, 2013.

Storm Damage Expense Rider

In its December 28, 2012 final rate case proceeding order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER) within 90 days following the order. PPL Electric filed its proposed SDER with the PUC 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. 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 May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. Although PPL Electric believes it has met the May 2011 requirement, the PUC is not expected to formally determine compliance for any EDC before the first quarter of 2014. 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 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.

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 June 1, 2009 through May 31, 2010 baseline year. 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 competitive 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 its January 24, 2013 final order, 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. In an order entered on May 23, 2013, the PUC approved PPL Electric's most recent filing with minor changes and 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 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013. In August 2013, PPL Electric will file its annual Smart Meter report and revised SMR charges to 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. A prehearing conference has been held and a litigation schedule set with evidentiary hearings scheduled for the end of October 2013. The case remains pending before the PUC.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

PPL Electric must follow the FERC's Uniform System of Accounts (USOA), which requires subsidiaries to be presented, for FERC reporting purposes, using the equity method of accounting unless a waiver has been granted. The FERC has granted waivers of this requirement to other utilities when alternative accounting would more accurately present the integrated operations of a utility and its subsidiaries. In March 2013, as part of a routine FERC audit of PPL and its subsidiaries, PPL Electric determined that it never obtained a waiver of the equity method accounting requirement for PPL Receivables Corporation (PPL Receivables). PPL Receivables is a wholly owned subsidiary of PPL Electric, formed in 2004 to purchase eligible accounts receivable and unbilled revenue of PPL Electric to collateralize commercial paper issuances and reduce borrowing costs. In March 2013, PPL Electric filed a request for waiver with the FERC that, if approved, would allow it to continue to consolidate the results of PPL Receivables with the results of PPL Electric, as it has done since 2004. Although PPL Electric may ultimately be successful in obtaining the waiver, the FERC may require PPL Electric to re-issue one or more of its prior FERC Form No. 1 filings. If re-issuance of FERC Form No. 1 filings were required by the FERC, PPL Electric's revenue requirement calculated under the formula rate could be negatively impacted. The impact, if any, is not known at this time but could range between $0 and $40 million, pre-tax. PPL Electric cannot predict the outcome of the waiver or audit proceedings, which remain pending before the FERC.

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 USOA. 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. In April 2013, Ofgem stated that their expectation was to issue a decision in the second half of 2013. On July 12, 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss incentive/penalty. Based on one element of the decision paper, WPD has concluded that certain data, which had previously served to reduce the liability calculation, could not be included. Additional information in the decision paper has increased the level of uncertainty regarding the ultimate settlement of this liability. WPD currently estimates the potential loss exposure to be in the range of $97 million to $251 million. As a result, during the three and six months ended June 30, 2013, WPD recorded a $24 million increase to the liability with a reduction to "Utility" revenue on the Statement of Income, increasing the liability to $97 million at June 30, 2013 compared with $94 million at December 31, 2012. Other changes to this line loss liability included reductions of $16 million resulting from the refund being included in tariffs starting in April 2013 and foreign exchange movement during the six months ended June 30, 2013. PPL cannot predict the outcome of this matter.