Utility Rate Regulation [Line Items]

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
		March 31,		December 31,		March 31,		December 31,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6
	Fuel adjustment clause		8		3
Total current regulatory assets		$	15	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	605	$	615	$	273	$	276
	Taxes recoverable through future rates		293		289		293		289
	Storm costs		149		154		30		31
	Unamortized loss on debt		106		110		74		77
	Interest rate swaps		62		69
	Accumulated cost of removal of utility plant		59		53		59		53
	Coal contracts (a)		9		11
	AROs		21		18
	Other		30		30		2		3
Total noncurrent regulatory assets		$	1,334	$	1,349	$	731	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	35	$	42	$	35	$	42
	ECR		9		7
	Gas supply clause		6		6
	Transmission service charge		5		2		5		2
	Transmission formula rate		7				7
	Other		12		16		6		9
Total current regulatory liabilities		$	74	$	73	$	53	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	658	$	651
	Coal contracts (a)		170		180
	Power purchase agreement - OVEC (a)		114		116
	Net deferred tax assets		38		39
	Act 129 compliance rider		12		7	$	12	$	7
	Defined benefit plans		9		9
	Other		8		8
Total noncurrent regulatory liabilities		$	1,009	$	1,010	$	12	$	7

		LKE				LG&E				KU
		March 31,		December 31,		March 31,		December 31,		March 31,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6	$	7	$	6
	Fuel adjustment clause		8		3		7		3	$	1
Total current regulatory assets		$	15	$	9	$	14	$	9	$	1

Noncurrent Regulatory Assets:
	Defined benefit plans	$	332	$	339	$	220	$	225	$	112	$	114
	Storm costs		119		123		64		66		55		57
	Unamortized loss on debt		32		33		20		21		12		12
	Interest rate swaps		62		69		62		69
	Coal contracts (a)		9		11		4		5		5		6
	AROs		21		18		12		11		9		7
	Other		28		27		7		6		21		21
Total noncurrent regulatory assets		$	603	$	620	$	389	$	403	$	214	$	217

Current Regulatory Liabilities:
		ECR	$	9	$	7					$	9	$	7
		Gas supply clause		6		6	$	6	$	6
		Other		6		7		4		4		2		3
Total current regulatory liabilities			$	21	$	20	$	10	$	10	$	11	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	658	$	651	$	287	$	286	$	371	$	365
	Coal contracts (a)			170		180		73		78		97		102
	Power purchase agreement - OVEC (a)			114		116		79		80		35		36
	Net deferred tax assets			38		39		31		31		7		8
	Defined benefit plans			9		9						9		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	997	$	1,003	$	473	$	478	$	524	$	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. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new NGCC. In addition, LG&E and KU also requested approval to purchase the Bluegrass CTs which are expected to provide up to 495 MW of peak generation supply. LG&E will own a 69% undivided interest, and KU will own a 31% undivided interest in the purchased assets. In November 2011, LG&E and KU filed an application with the FERC requesting approval to purchase the Bluegrass CTs. In conjunction with these developments, in 2015, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant and also one coal-fired generating unit at KU's Tyrone plant and two at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

LG&E and KU anticipate that the NGCC construction and the acquisition of the Bluegrass CTs could require up to $800 million (comprised of up to $300 million for LG&E and up to $500 million for KU) in capital costs including related transmission projects. See Note 8 for additional information. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. In May 2012, the KPSC issued an order approving the request to build the NGCC and purchase the Bluegrass CTs. Also, on May 4, 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to implementation of satisfactory mitigation measures to address market-power concerns. FERC approval of the proposed mitigation measures is required. LG&E and KU are reviewing the order's conditions and their impact on the closing conditions under the Bluegrass CTs purchase contract, as well as other regulatory, operational and economic aspects of the transaction. PPL, LKE, LG&E and KU cannot currently predict the ultimate outcome of this matter.

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. Based upon the actual earned rate of return on common equity for 2011 and the current estimates of the outcome of an ASSD filing in 2012, LG&E and KU have not recognized any impact of the ASSD in the financial statements. 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.

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.

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 increasing 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. No petition requesting permission to establish a distribution system improvements charge may be filed with the PUC before January 1, 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 June 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. PPL Electric filed a response to that formal challenge. PPL Electric cannot predict the outcome of these two 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 $51 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 March 31, 2012 and December 31, 2011. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $173 million liability recorded at March 31, 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 used to calculate the final line loss incentive/penalty for the 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 and in April 2012, WPD submitted further data as requested by Ofgem. PPL cannot predict the outcome of this matter, but expects resolution to occur before the end of 2012.

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
		March 31,		December 31,		March 31,		December 31,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6
	Fuel adjustment clause		8		3
Total current regulatory assets		$	15	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	605	$	615	$	273	$	276
	Taxes recoverable through future rates		293		289		293		289
	Storm costs		149		154		30		31
	Unamortized loss on debt		106		110		74		77
	Interest rate swaps		62		69
	Accumulated cost of removal of utility plant		59		53		59		53
	Coal contracts (a)		9		11
	AROs		21		18
	Other		30		30		2		3
Total noncurrent regulatory assets		$	1,334	$	1,349	$	731	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	35	$	42	$	35	$	42
	ECR		9		7
	Gas supply clause		6		6
	Transmission service charge		5		2		5		2
	Transmission formula rate		7				7
	Other		12		16		6		9
Total current regulatory liabilities		$	74	$	73	$	53	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	658	$	651
	Coal contracts (a)		170		180
	Power purchase agreement - OVEC (a)		114		116
	Net deferred tax assets		38		39
	Act 129 compliance rider		12		7	$	12	$	7
	Defined benefit plans		9		9
	Other		8		8
Total noncurrent regulatory liabilities		$	1,009	$	1,010	$	12	$	7

		LKE				LG&E				KU
		March 31,		December 31,		March 31,		December 31,		March 31,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	7	$	6	$	7	$	6
	Fuel adjustment clause		8		3		7		3	$	1
Total current regulatory assets		$	15	$	9	$	14	$	9	$	1

Noncurrent Regulatory Assets:
	Defined benefit plans	$	332	$	339	$	220	$	225	$	112	$	114
	Storm costs		119		123		64		66		55		57
	Unamortized loss on debt		32		33		20		21		12		12
	Interest rate swaps		62		69		62		69
	Coal contracts (a)		9		11		4		5		5		6
	AROs		21		18		12		11		9		7
	Other		28		27		7		6		21		21
Total noncurrent regulatory assets		$	603	$	620	$	389	$	403	$	214	$	217

Current Regulatory Liabilities:
		ECR	$	9	$	7					$	9	$	7
		Gas supply clause		6		6	$	6	$	6
		Other		6		7		4		4		2		3
Total current regulatory liabilities			$	21	$	20	$	10	$	10	$	11	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	658	$	651	$	287	$	286	$	371	$	365
	Coal contracts (a)			170		180		73		78		97		102
	Power purchase agreement - OVEC (a)			114		116		79		80		35		36
	Net deferred tax assets			38		39		31		31		7		8
	Defined benefit plans			9		9						9		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	997	$	1,003	$	473	$	478	$	524	$	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. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new NGCC. In addition, LG&E and KU also requested approval to purchase the Bluegrass CTs which are expected to provide up to 495 MW of peak generation supply. LG&E will own a 69% undivided interest, and KU will own a 31% undivided interest in the purchased assets. In November 2011, LG&E and KU filed an application with the FERC requesting approval to purchase the Bluegrass CTs. In conjunction with these developments, in 2015, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant and also one coal-fired generating unit at KU's Tyrone plant and two at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

LG&E and KU anticipate that the NGCC construction and the acquisition of the Bluegrass CTs could require up to $800 million (comprised of up to $300 million for LG&E and up to $500 million for KU) in capital costs including related transmission projects. See Note 8 for additional information. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. In May 2012, the KPSC issued an order approving the request to build the NGCC and purchase the Bluegrass CTs. Also, on May 4, 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to implementation of satisfactory mitigation measures to address market-power concerns. FERC approval of the proposed mitigation measures is required. LG&E and KU are reviewing the order's conditions and their impact on the closing conditions under the Bluegrass CTs purchase contract, as well as other regulatory, operational and economic aspects of the transaction. PPL, LKE, LG&E and KU cannot currently predict the ultimate outcome of this matter.

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. Based upon the actual earned rate of return on common equity for 2011 and the current estimates of the outcome of an ASSD filing in 2012, LG&E and KU have not recognized any impact of the ASSD in the financial statements. 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.

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.

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 increasing 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. No petition requesting permission to establish a distribution system improvements charge may be filed with the PUC before January 1, 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 June 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. PPL Electric filed a response to that formal challenge. PPL Electric cannot predict the outcome of these two 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 $51 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 March 31, 2012 and December 31, 2011. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $173 million liability recorded at March 31, 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 used to calculate the final line loss incentive/penalty for the 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 and in April 2012, WPD submitted further data as requested by Ofgem. PPL cannot predict the outcome of this matter, but expects resolution to occur before the end of 2012.

Utility Rate Regulation [Line Items]