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,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6
	Fuel adjustment clause		10		3
Total current regulatory assets		$	17	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	595	$	615	$	270	$	276
	Taxes recoverable through future rates		297		289		297		289
	Storm costs		148		154		32		31
	Unamortized loss on debt		103		110		71		77
	Interest rate swaps		71		69
	Accumulated cost of removal of utility plant		62		53		62		53
	Coal contracts (a)		7		11
	AROs		23		18
	Other		29		30		2		3
Total noncurrent regulatory assets		$	1,335	$	1,349	$	734	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	21	$	42	$	21	$	42
	ECR		9		7
	Gas supply clause		5		6
	Transmission service charge		4		2		4		2
	Transmission formula rate		7				7
	Universal service rider		7				7
	Other		5		16		3		9
Total current regulatory liabilities		$	58	$	73	$	42	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	666	$	651
	Coal contracts (a)		161		180
	Power purchase agreement - OVEC (a)		112		116
	Net deferred tax assets		37		39
	Act 129 compliance rider		9		7	$	9	$	7
	Defined benefit plans		10		9
	Other		8		8
Total noncurrent regulatory liabilities		$	1,003	$	1,010	$	9	$	7

		LKE				LG&E				KU
		June 30,		December 31,		June 30,		December 31,		June 30,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6	$	7	$	6
	Fuel adjustment clause		10		3		6		3	$	4
Total current regulatory assets		$	17	$	9	$	13	$	9	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	325	$	339	$	215	$	225	$	110	$	114
	Storm costs		116		123		63		66		53		57
	Unamortized loss on debt		32		33		21		21		11		12
	Interest rate swaps		71		69		71		69
	Coal contracts (a)		7		11		3		5		4		6
	AROs		23		18		12		11		11		7
	Other		27		27		6		6		21		21
Total noncurrent regulatory assets		$	601	$	620	$	391	$	403	$	210	$	217

Current Regulatory Liabilities:
		ECR	$	9	$	7					$	9	$	7
		Gas supply clause		5		6	$	5	$	6
		Other		2		7		2		4				3
Total current regulatory liabilities			$	16	$	20	$	7	$	10	$	9	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	666	$	651	$	291	$	286	$	375	$	365
	Coal contracts (a)			161		180		70		78		91		102
	Power purchase agreement - OVEC (a)			112		116		78		80		34		36
	Net deferred tax assets			37		39		30		31		7		8
	Defined benefit plans			10		9						10		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	994	$	1,003	$	472	$	478	$	522	$	525

(a) These regulatory assets and liabilities were recorded as offsets to certain intangible assets and liabilities that were recorded at fair value upon the acquisition of LKE.

Regulatory Matters

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

CPCN Filing

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. In May 2012, the KPSC issued an order approving the request to build the NGCC. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new NGCC. A formal request for recovery of the costs associated with the NGCC construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. See Note 8 for additional information.

In conjunction with this construction and to meet new, stricter EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant, one coal-fired generating unit at KU's Tyrone plant and two coal-fired generating units at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

The CPCN application also requested approval to purchase the Bluegrass CTs. The May 2012 KPSC approval included authority to complete the Bluegrass CT acquisition. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the purchase contract for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC. LG&E and KU are currently assessing the impact of the Bluegrass contract termination and potential future generation capacity options. See Note 8 for additional information.

Kentucky Acquisition Commitments

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect, currently expected to be 2013. Therefore, due to the timing of the current rate case in Kentucky, no further ASSD filings are expected.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. The proposed base rate increases would result in electric rate increases of 6.9% at LG&E and 6.5% at KU and a gas rate increase of 7.0% at LG&E and would be effective in January 2013. LG&E's and KU's applications include requests for authorized returns-on-equity at LG&E and KU of 11% each. A hearing on these matters is expected to be scheduled during the fourth quarter of 2012. LG&E and KU cannot predict the outcome of these proceedings.

Pennsylvania Activities (PPL and PPL Electric)

PUC Investigation of Retail 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 this phase 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. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan. In March 2012, the PUC Staff issued three possible models for the default service "end state" and the PUC held a hearing regarding those three models. PPL Electric cannot predict the outcome of the investigation or its impact on PPL Electric's financial condition or results of operation.

Legislation - Regulatory Procedures and Mechanisms

In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation authorizing the PUC to approve regulatory procedures and mechanisms to provide more timely recovery of a utility's costs. In the first quarter of 2012, the Governor signed an amended version of the legislation (Act 11 of 2012), which became effective April 14, 2012. The legislation authorizes the PUC to approve two specific ratemaking mechanisms -- a fully projected future test year and, subject to certain conditions, a distribution system improvements charge. Such alternative ratemaking procedures and mechanisms 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. The PUC staff has initiated a process to develop filing guidelines and a model tariff for the distribution system improvements charge. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11 of 2012. No petition requesting permission to establish a distribution system improvements charge may be filed with the PUC before January 1, 2013.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million. The proposed distribution revenue rate increase would result in a 2.9% increase over PPL Electric's total rates at the time of filing and be effective January 1, 2013. PPL Electric's application includes a request for an authorized return on equity of 11.25%. Hearings on this matter are scheduled during August 2012 and a decision is expected in the fourth quarter of 2012. PPL Electric cannot predict the outcome of this proceeding.

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 exposed 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. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. To date, PPL Electric has met the 2011 requirement, subject to the PUC's verification.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2012 and adopt additional reductions if the benefits of the program exceed the costs. In March 2012, the PUC began the process of designing Phase II of the EE&C program. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program with consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish any demand reduction targets for the Phase II program. EDCs must file Phase II plans with the PUC by November 1, 2012.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive 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 the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric continues 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 proposes a process to obtain supply for its default service customers and it proposes a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. The PUC has assigned PPL Electric's plan to an Administrative Law Judge for hearings and a recommended decision. The PUC is expected to rule on the plan in 2013.

Federal Matters (PPL and PPL Electric)

FERC Formula Rates

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.

In May 2010, PPL Electric initiated its formula rate 2010 Annual Update. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.

In May 2011, PPL Electric initiated its formula rate 2011 Annual Update. In October 2011, the group of municipal customers filed a preliminary challenge to the update and, in December 2011, filed a formal challenge. In January 2012, PPL Electric filed a response to that formal challenge.

In May 2012, PPL Electric initiated its formula rate 2012 Annual Update which currently is in the 180-day review and challenge period. PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of approximately $50 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheets at June 30, 2012 and December 31, 2011. In May 2012, the FERC issued an order approving PPL Electric's request effective June 1, 2012.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $167 million liability recorded at June 30, 2012 compared with $170 million at December 31, 2011, calculated in accordance with Ofgem's accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013 together with a proposal to remove the line loss incentive/penalty for DPCR5. 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,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6
	Fuel adjustment clause		10		3
Total current regulatory assets		$	17	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	595	$	615	$	270	$	276
	Taxes recoverable through future rates		297		289		297		289
	Storm costs		148		154		32		31
	Unamortized loss on debt		103		110		71		77
	Interest rate swaps		71		69
	Accumulated cost of removal of utility plant		62		53		62		53
	Coal contracts (a)		7		11
	AROs		23		18
	Other		29		30		2		3
Total noncurrent regulatory assets		$	1,335	$	1,349	$	734	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	21	$	42	$	21	$	42
	ECR		9		7
	Gas supply clause		5		6
	Transmission service charge		4		2		4		2
	Transmission formula rate		7				7
	Universal service rider		7				7
	Other		5		16		3		9
Total current regulatory liabilities		$	58	$	73	$	42	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	666	$	651
	Coal contracts (a)		161		180
	Power purchase agreement - OVEC (a)		112		116
	Net deferred tax assets		37		39
	Act 129 compliance rider		9		7	$	9	$	7
	Defined benefit plans		10		9
	Other		8		8
Total noncurrent regulatory liabilities		$	1,003	$	1,010	$	9	$	7

		LKE				LG&E				KU
		June 30,		December 31,		June 30,		December 31,		June 30,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6	$	7	$	6
	Fuel adjustment clause		10		3		6		3	$	4
Total current regulatory assets		$	17	$	9	$	13	$	9	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	325	$	339	$	215	$	225	$	110	$	114
	Storm costs		116		123		63		66		53		57
	Unamortized loss on debt		32		33		21		21		11		12
	Interest rate swaps		71		69		71		69
	Coal contracts (a)		7		11		3		5		4		6
	AROs		23		18		12		11		11		7
	Other		27		27		6		6		21		21
Total noncurrent regulatory assets		$	601	$	620	$	391	$	403	$	210	$	217

Current Regulatory Liabilities:
		ECR	$	9	$	7					$	9	$	7
		Gas supply clause		5		6	$	5	$	6
		Other		2		7		2		4				3
Total current regulatory liabilities			$	16	$	20	$	7	$	10	$	9	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	666	$	651	$	291	$	286	$	375	$	365
	Coal contracts (a)			161		180		70		78		91		102
	Power purchase agreement - OVEC (a)			112		116		78		80		34		36
	Net deferred tax assets			37		39		30		31		7		8
	Defined benefit plans			10		9						10		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	994	$	1,003	$	472	$	478	$	522	$	525

(a) These regulatory assets and liabilities were recorded as offsets to certain intangible assets and liabilities that were recorded at fair value upon the acquisition of LKE.

Regulatory Matters

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

CPCN Filing

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. In May 2012, the KPSC issued an order approving the request to build the NGCC. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new NGCC. A formal request for recovery of the costs associated with the NGCC construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. See Note 8 for additional information.

In conjunction with this construction and to meet new, stricter EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant, one coal-fired generating unit at KU's Tyrone plant and two coal-fired generating units at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

The CPCN application also requested approval to purchase the Bluegrass CTs. The May 2012 KPSC approval included authority to complete the Bluegrass CT acquisition. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the purchase contract for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC. LG&E and KU are currently assessing the impact of the Bluegrass contract termination and potential future generation capacity options. See Note 8 for additional information.

Kentucky Acquisition Commitments

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect, currently expected to be 2013. Therefore, due to the timing of the current rate case in Kentucky, no further ASSD filings are expected.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. The proposed base rate increases would result in electric rate increases of 6.9% at LG&E and 6.5% at KU and a gas rate increase of 7.0% at LG&E and would be effective in January 2013. LG&E's and KU's applications include requests for authorized returns-on-equity at LG&E and KU of 11% each. A hearing on these matters is expected to be scheduled during the fourth quarter of 2012. LG&E and KU cannot predict the outcome of these proceedings.

Pennsylvania Activities (PPL and PPL Electric)

PUC Investigation of Retail 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 this phase 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. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan. In March 2012, the PUC Staff issued three possible models for the default service "end state" and the PUC held a hearing regarding those three models. PPL Electric cannot predict the outcome of the investigation or its impact on PPL Electric's financial condition or results of operation.

Legislation - Regulatory Procedures and Mechanisms

In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation authorizing the PUC to approve regulatory procedures and mechanisms to provide more timely recovery of a utility's costs. In the first quarter of 2012, the Governor signed an amended version of the legislation (Act 11 of 2012), which became effective April 14, 2012. The legislation authorizes the PUC to approve two specific ratemaking mechanisms -- a fully projected future test year and, subject to certain conditions, a distribution system improvements charge. Such alternative ratemaking procedures and mechanisms 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. The PUC staff has initiated a process to develop filing guidelines and a model tariff for the distribution system improvements charge. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11 of 2012. No petition requesting permission to establish a distribution system improvements charge may be filed with the PUC before January 1, 2013.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million. The proposed distribution revenue rate increase would result in a 2.9% increase over PPL Electric's total rates at the time of filing and be effective January 1, 2013. PPL Electric's application includes a request for an authorized return on equity of 11.25%. Hearings on this matter are scheduled during August 2012 and a decision is expected in the fourth quarter of 2012. PPL Electric cannot predict the outcome of this proceeding.

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 exposed 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. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. To date, PPL Electric has met the 2011 requirement, subject to the PUC's verification.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2012 and adopt additional reductions if the benefits of the program exceed the costs. In March 2012, the PUC began the process of designing Phase II of the EE&C program. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program with consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish any demand reduction targets for the Phase II program. EDCs must file Phase II plans with the PUC by November 1, 2012.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive 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 the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric continues 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 proposes a process to obtain supply for its default service customers and it proposes a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. The PUC has assigned PPL Electric's plan to an Administrative Law Judge for hearings and a recommended decision. The PUC is expected to rule on the plan in 2013.

Federal Matters (PPL and PPL Electric)

FERC Formula Rates

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.

In May 2010, PPL Electric initiated its formula rate 2010 Annual Update. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.

In May 2011, PPL Electric initiated its formula rate 2011 Annual Update. In October 2011, the group of municipal customers filed a preliminary challenge to the update and, in December 2011, filed a formal challenge. In January 2012, PPL Electric filed a response to that formal challenge.

In May 2012, PPL Electric initiated its formula rate 2012 Annual Update which currently is in the 180-day review and challenge period. PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of approximately $50 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheets at June 30, 2012 and December 31, 2011. In May 2012, the FERC issued an order approving PPL Electric's request effective June 1, 2012.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $167 million liability recorded at June 30, 2012 compared with $170 million at December 31, 2011, calculated in accordance with Ofgem's accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013 together with a proposal to remove the line loss incentive/penalty for DPCR5. 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,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6
	Fuel adjustment clause		10		3
Total current regulatory assets		$	17	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	595	$	615	$	270	$	276
	Taxes recoverable through future rates		297		289		297		289
	Storm costs		148		154		32		31
	Unamortized loss on debt		103		110		71		77
	Interest rate swaps		71		69
	Accumulated cost of removal of utility plant		62		53		62		53
	Coal contracts (a)		7		11
	AROs		23		18
	Other		29		30		2		3
Total noncurrent regulatory assets		$	1,335	$	1,349	$	734	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	21	$	42	$	21	$	42
	ECR		9		7
	Gas supply clause		5		6
	Transmission service charge		4		2		4		2
	Transmission formula rate		7				7
	Universal service rider		7				7
	Other		5		16		3		9
Total current regulatory liabilities		$	58	$	73	$	42	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	666	$	651
	Coal contracts (a)		161		180
	Power purchase agreement - OVEC (a)		112		116
	Net deferred tax assets		37		39
	Act 129 compliance rider		9		7	$	9	$	7
	Defined benefit plans		10		9
	Other		8		8
Total noncurrent regulatory liabilities		$	1,003	$	1,010	$	9	$	7

		LKE				LG&E				KU
		June 30,		December 31,		June 30,		December 31,		June 30,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6	$	7	$	6
	Fuel adjustment clause		10		3		6		3	$	4
Total current regulatory assets		$	17	$	9	$	13	$	9	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	325	$	339	$	215	$	225	$	110	$	114
	Storm costs		116		123		63		66		53		57
	Unamortized loss on debt		32		33		21		21		11		12
	Interest rate swaps		71		69		71		69
	Coal contracts (a)		7		11		3		5		4		6
	AROs		23		18		12		11		11		7
	Other		27		27		6		6		21		21
Total noncurrent regulatory assets		$	601	$	620	$	391	$	403	$	210	$	217

Current Regulatory Liabilities:
		ECR	$	9	$	7					$	9	$	7
		Gas supply clause		5		6	$	5	$	6
		Other		2		7		2		4				3
Total current regulatory liabilities			$	16	$	20	$	7	$	10	$	9	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	666	$	651	$	291	$	286	$	375	$	365
	Coal contracts (a)			161		180		70		78		91		102
	Power purchase agreement - OVEC (a)			112		116		78		80		34		36
	Net deferred tax assets			37		39		30		31		7		8
	Defined benefit plans			10		9						10		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	994	$	1,003	$	472	$	478	$	522	$	525

(a) These regulatory assets and liabilities were recorded as offsets to certain intangible assets and liabilities that were recorded at fair value upon the acquisition of LKE.

Regulatory Matters

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

CPCN Filing

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. In May 2012, the KPSC issued an order approving the request to build the NGCC. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new NGCC. A formal request for recovery of the costs associated with the NGCC construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. See Note 8 for additional information.

In conjunction with this construction and to meet new, stricter EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant, one coal-fired generating unit at KU's Tyrone plant and two coal-fired generating units at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

The CPCN application also requested approval to purchase the Bluegrass CTs. The May 2012 KPSC approval included authority to complete the Bluegrass CT acquisition. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the purchase contract for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC. LG&E and KU are currently assessing the impact of the Bluegrass contract termination and potential future generation capacity options. See Note 8 for additional information.

Kentucky Acquisition Commitments

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect, currently expected to be 2013. Therefore, due to the timing of the current rate case in Kentucky, no further ASSD filings are expected.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. The proposed base rate increases would result in electric rate increases of 6.9% at LG&E and 6.5% at KU and a gas rate increase of 7.0% at LG&E and would be effective in January 2013. LG&E's and KU's applications include requests for authorized returns-on-equity at LG&E and KU of 11% each. A hearing on these matters is expected to be scheduled during the fourth quarter of 2012. LG&E and KU cannot predict the outcome of these proceedings.

Pennsylvania Activities (PPL and PPL Electric)

PUC Investigation of Retail 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 this phase 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. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan. In March 2012, the PUC Staff issued three possible models for the default service "end state" and the PUC held a hearing regarding those three models. PPL Electric cannot predict the outcome of the investigation or its impact on PPL Electric's financial condition or results of operation.

Legislation - Regulatory Procedures and Mechanisms

In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation authorizing the PUC to approve regulatory procedures and mechanisms to provide more timely recovery of a utility's costs. In the first quarter of 2012, the Governor signed an amended version of the legislation (Act 11 of 2012), which became effective April 14, 2012. The legislation authorizes the PUC to approve two specific ratemaking mechanisms -- a fully projected future test year and, subject to certain conditions, a distribution system improvements charge. Such alternative ratemaking procedures and mechanisms 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. The PUC staff has initiated a process to develop filing guidelines and a model tariff for the distribution system improvements charge. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11 of 2012. No petition requesting permission to establish a distribution system improvements charge may be filed with the PUC before January 1, 2013.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million. The proposed distribution revenue rate increase would result in a 2.9% increase over PPL Electric's total rates at the time of filing and be effective January 1, 2013. PPL Electric's application includes a request for an authorized return on equity of 11.25%. Hearings on this matter are scheduled during August 2012 and a decision is expected in the fourth quarter of 2012. PPL Electric cannot predict the outcome of this proceeding.

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 exposed 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. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. To date, PPL Electric has met the 2011 requirement, subject to the PUC's verification.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2012 and adopt additional reductions if the benefits of the program exceed the costs. In March 2012, the PUC began the process of designing Phase II of the EE&C program. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program with consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish any demand reduction targets for the Phase II program. EDCs must file Phase II plans with the PUC by November 1, 2012.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive 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 the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric continues 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 proposes a process to obtain supply for its default service customers and it proposes a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. The PUC has assigned PPL Electric's plan to an Administrative Law Judge for hearings and a recommended decision. The PUC is expected to rule on the plan in 2013.

Federal Matters (PPL and PPL Electric)

FERC Formula Rates

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.

In May 2010, PPL Electric initiated its formula rate 2010 Annual Update. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.

In May 2011, PPL Electric initiated its formula rate 2011 Annual Update. In October 2011, the group of municipal customers filed a preliminary challenge to the update and, in December 2011, filed a formal challenge. In January 2012, PPL Electric filed a response to that formal challenge.

In May 2012, PPL Electric initiated its formula rate 2012 Annual Update which currently is in the 180-day review and challenge period. PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of approximately $50 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheets at June 30, 2012 and December 31, 2011. In May 2012, the FERC issued an order approving PPL Electric's request effective June 1, 2012.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $167 million liability recorded at June 30, 2012 compared with $170 million at December 31, 2011, calculated in accordance with Ofgem's accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013 together with a proposal to remove the line loss incentive/penalty for DPCR5. PPL cannot predict the outcome of this matter.