Public Utilities Disclosure [Line Items]

6. Utility Rate Regulation

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

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

		PPL				PPL Electric
		September 30,		December 31,		September 30,		December 31,
		2011		2010		2011		2010

Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider	$	3		10	$	3		10
	Fuel adjustment clause		10		3
	Other		6		27				8
Total current regulatory assets		$	19	$	85	$	3	$	63

Noncurrent Regulatory Assets:
	Defined benefit plans	$	586	$	592	$	256	$	262
	Taxes recoverable through future rates		270		254		270		254
	Storm costs		132		129		6		7
	Unamortized loss on debt		113		61		80		27
	Interest rate swaps		66		43
	Accumulated cost of removal of utility plant (b)		46		35		46		35
	Coal contracts (c)		14		22
	Other		50		44		5		7
Total noncurrent regulatory assets		$	1,277	$	1,180	$	663	$	592

Current Regulatory Liabilities:
	Coal contracts (c)	$	12	$	46
	Generation supply charge (a)		37			$	37
	ECR		8		12
	PURTA tax		3		10		3	$	10
	DSM		10		10
	Transmission service charge		1		8		1		8
	Other		12		23		5
Total current regulatory liabilities		$	83	$	109	$	46	$	18

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	646	$	623
	Coal contracts (c)		188		213
	Power purchase agreement - OVEC (c)		118		124
	Net deferred tax assets		37		40
	Act 129 compliance rider		13		14	$	13	$	14
	Defined benefit plans		10		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,020	$	1,031	$	13	$	14

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2011		2010		2011		2010		2011		2010

Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)	$	1		5				1	$	1	$	4
	Gas supply clause		5		4	$	5		4
	Fuel adjustment clause		10		3		5		3		5
	Virginia fuel factor				5								5
Total current regulatory assets		$	16	$	22	$	10	$	13	$	6	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	330	$	330	$	213	$	213	$	117	$	117
	Storm costs		126		122		67		65		59		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		66		43		66		43
	Coal contracts (c)		14		22		6		8		8		14
	Other		45		37		17		16		28		21
Total noncurrent regulatory assets		$	614	$	588	$	390	$	367	$	224	$	221

Current Regulatory Liabilities:
		Coal contracts (c)	$	12	$	46	$	8	$	31	$	4	$	15
		ECR		8		12		1				7		12
		DSM		10		10		6		5		4		5
		Other		7		23		5		15		2		8
Total current regulatory liabilities			$	37	$	91	$	20	$	51	$	17	$	40

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	646	$	623	$	284	$	275	$	362	$	348
	Coal contracts (c)			188		213		80		87		108		126
	Power purchase agreement - OVEC (c)			118		124		82		86		36		38
	Net deferred tax assets			37		40		32		34		5		6
	Defined benefit plans			10		10						10		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,007	$	1,017	$	481	$	483	$	526	$	534

(a) PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at September 30, 2011, reflecting the impacts of changes in customer billing cycles, the timing of rate reconciliation filings, the levels of customers choosing alternative energy suppliers and other factors. Because customer rates are designed to collect the costs of PPL Electric's energy purchases to meet its PLR requirements, there is minimal impact on earnings.

(b) The December 31, 2010 balance of accumulated cost of removal of utility plant was reclassified from "Accumulated depreciation - regulated utility plant" to noncurrent "Regulatory assets" on the Balance Sheets. These costs will continue to be included in future rate proceedings.

(c) 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)

Environmental Upgrades

In order to achieve compliance with new and pending federal EPA regulations including CSAPR, National Ambient Air Quality Standards and the MACT rule, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses, as incurred. The ECR plans detail upgrades that will be made to certain of their coal-fired generating stations to continue to be compliant with EPA regulations.

LG&E requested $1.4 billion to modernize the sulfur dioxide scrubbers at the Mill Creek generating station as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at Mill Creek and for Unit 1 at Trimble County. In its KPSC application, LG&E estimated the impact on rates to LG&E's electric customers to be an increase of 2.3% in 2012, growing to an increase of 19.2% by 2016. KU requested $1.1 billion for upgrades that include fabric-filter baghouse systems for increased particulate and mercury control on units at the E.W. Brown and Ghent generating stations and the conversion of a wet storage facility to a dry landfill at the E.W. Brown generating station. In its KPSC application, KU estimated the impact on rates to KU's electric customers to be an increase of 1.5% in 2012, growing to an increase of 12.2% by 2016.

Certain parties have been granted intervenor status in the ECR proceedings. The KPSC issued a procedural schedule under which data discovery is expected to continue into the fourth quarter. A KPSC order is anticipated to be issued in December 2011. LG&E and KU cannot predict the outcome of these proceedings.

IRP

IRP regulations in Kentucky require major utilities to make triennial IRP filings with the KPSC. In April 2011, LG&E and KU filed their 2011 joint IRP with the KPSC. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information. In May 2011, the KPSC issued a procedural schedule and data discovery will continue through the fourth quarter. Pursuant to a December 2008 Order, KU filed the 2011 joint IRP with the VSCC in September 2011, with certain supplemental information as required by this Order. The IRP assumes approximately 500 MW of peak demand reductions by 2017 through existing or expanded DSM or energy efficiency programs. Implementation of the major findings of the IRP is subject to further analysis and decision-making and further regulatory approvals.

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 station site. KU will own a 78% undivided interest, and LG&E will own a 22% undivided interest, in the new NGCC. In addition, LG&E and KU also requested approval to purchase three additional natural gas combustion turbines from Bluegrass Generation Company, L.L.C. that are expected to provide up to 495 MW of peak generation supply (the Bluegrass Plant). In conjunction with these developments, at the end of 2015 LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run station and also coal-fired generating units at KU's Tyrone and Green River stations. These generating stations represent 797 MW of combined summer capacity.

LG&E and KU anticipate that the NGCC construction and Bluegrass Plant acquisition 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. Formal requests for recovery of the costs associated with the NGCC and Bluegrass Plant acquisition were not included in the CPCN filing with the KPSC, but are expected to be included in a future base rate case filing. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery, but no hearing, scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

DSM/Energy Efficiency

In April 2011, LG&E and KU filed a DSM application to expand existing energy efficiency programs and implement new energy efficiency programs. Discovery and evidentiary phases have been completed and a KPSC order is anticipated during the fourth quarter of 2011. Any increase in rates will not be implemented until an order is issued by the KPSC.

PPL's Acquisition of LKE

In September 2010, the KPSC approved a settlement agreement among PPL and all of the intervening parties to PPL's joint application to the KPSC for approval of its acquisition of ownership and control of LKE, LG&E and KU. In the settlement agreement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013. Under the terms of the settlement, LG&E and KU retain the right to seek KPSC approval for the deferral of "extraordinary and uncontrollable costs," such as significant storm restoration costs, if incurred. Additionally, interim rate adjustments will continue to be permissible during that period for existing recovery mechanisms such as the ECR and DSM.

Storm Costs (PPL, LKE and LG&E)

In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011, requesting approval of a regulatory asset recorded to defer, for future recovery, $7 million in incremental operation and maintenance expenses related to the storm restoration. The KPSC has issued a procedural schedule for discovery relating to the application during the fourth quarter.

Virginia Activities (PPL, LKE and KU)

Rate Case

In April 2011, KU filed an application with the VSCC requesting an annual increase in electric base rates for its Virginia jurisdictional customers of $9 million, or 14%. The proposed increase reflected a rate of return on rate base of 8%, based on a return on equity of 11%, inclusive of expenditures to complete TC2, all new sulfur dioxide scrubbers, recovery over five years of a 2009 storm regulatory asset and various other adjustments to revenue and expenses for the test year ended December 31, 2010. In September 2011, a settlement stipulation was reached between KU and the VSCC Staff and filed with the VSCC for consideration. In October 2011, the VSCC approved the stipulation with two modifications that were accepted by KU. The VSCC issued an Order closing the proceeding in October 2011. The approved annual revenue increase is $7 million with new base rates effective November 1, 2011.

Levelized Fuel Factor

In February 2011, KU filed an application with the VSCC seeking approval of an increase in its fuel cost factor beginning with service rendered in April 2011. In March 2011, a hearing was held on KU's requested fuel factor and an Order was issued approving a revised fuel factor to be in effect beginning with service rendered on and after April 1, 2011, with recovery of the regulatory asset for prior period under-recoveries over a three-year period.

Storm Costs

In December 2009, a major snowstorm hit KU's Virginia service area causing approximately 30,000 customer outages. During the normal 2009 Virginia Annual Information Filing (AIF), KU requested that the VSCC establish a regulatory asset and defer for future recovery $6 million in incremental operation and maintenance expenses related to the storm restoration. In March 2011, the VSCC Staff issued its report on KU's 2009 AIF stating that it considered this storm damage to be extraordinary, non-recurring and material to KU. The Staff Report also recommended establishing a regulatory asset for these costs, with recovery over a five-year period upon approval in the next base rate case. In March 2011, a regulatory asset of $6 million was established for actual costs incurred. In June 2011, the VSCC issued an Order approving the recommendations contained in the Staff Report.

Pennsylvania Activities

(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania electric utilities to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. Utilities not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, Electric Distribution Companies (EDCs) must develop and 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 2011 and 3.0% by 2013, and reduced peak demand of 4.5% for the 100 hours of highest demand by 2013. To date, PPL Electric has met the 2011 requirement, subject to the PUC's verification. 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. The plan includes 14 programs, all of which are voluntary for customers. The plan includes a proposed rate mechanism for recovery of all costs incurred by PPL Electric to implement the plan. In September 2010, PPL Electric filed its Program Year 1 Annual Report and Process Evaluation Report. PPL Electric also filed a petition requesting permission to modify two components of its EE&C Plan. The PUC issued its Final Order in January 2011, approving the changes proposed by PPL Electric and directing PPL Electric to re-file its plan to reflect all changes made since its initial approval. In February 2011, PPL Electric filed the changes to its plan and in May 2011, the PUC approved those changes.

Act 129 also requires installation of smart meters for new construction, upon the request of consumers at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs will be able to recover the costs of providing smart metering technology. In August 2009, PPL Electric filed its proposed smart meter technology procurement and installation plan with the PUC. All of PPL Electric's metered customers currently have smart meters installed at their service locations, and PPL Electric's current advanced metering technology generally satisfies the requirements of Act 129 and does not need to be replaced. In June 2010, the PUC entered its order approving PPL Electric's smart meter plan with several modifications. In compliance with the Order, in the third quarter of 2010, PPL Electric submitted a revised plan with a cost estimate of $38 million to be incurred over a five-year period, beginning in 2009, and filed a rider to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of its smart meter program. In August 2011, PPL Electric filed with the PUC an annual report describing the actions it is taking under its smart meter plan in 2011 and will take in 2012. PPL Electric also submitted proposed Smart Meter Rider charges to be effective January 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 up 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.

Under Act 129, the DSP competitive procurement plan must ensure adequate and reliable service "at least cost to customers" over time. Act 129 grants the PUC authority to extend long-term power contracts up to 20 years, if necessary, to achieve the "least cost" standard. The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric has begun purchasing under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

PUC Investigation of Retail Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market which will be conducted in two phases. Phase one will address the status of the current retail market and explore potential changes. Questions promulgated by the PUC for this phase of the investigation focus primarily on default service issues. In June 2011, interested parties filed comments and the PUC held a hearing in this phase of the investigation. In July 2011, the PUC entered an order initiating phase two of the investigation which will study how best to address issues identified by the PUC as being most relevant to improving the current retail electricity market. The PUC issued a tentative order in October 2011 addressing issues associated with the timing and various other details of EDCs' default service procurement plans. Parties will have an opportunity to comment on that tentative order. The PUC also has scheduled a hearing in this phase of the investigation in November 2011. It is likely that investigation will not be completed before the end of the year. 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 that would authorize the PUC to approve regulatory procedures and mechanisms to provide for more timely recovery of a utility's costs. Those procedures and mechanisms include, but are not limited to, the use of a fully projected test year and an automatic adjustment clause to recover certain capital costs and related operating expenses. In October 2011, the legislation was passed by the Pennsylvania House of Representatives. It will now be considered by the Pennsylvania Senate. PPL Electric is working with other stakeholders to support passage of this legislation.

Unamortized Loss on Debt

As further discussed in Note 7, in July 2011 PPL Electric redeemed Senior Secured Bonds for $458 million, plus accrued interest. The redemption premium and the unamortized financing costs of $59 million were recorded as a regulatory asset which will be amortized over the life of the replacement debt.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during the three and nine months ended September 30, 2011 resulting in total restoration costs of $34 million and $59 million, of which $23 million and $39 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms has exceeded policy limits. Probable insurance recoveries recorded during the three and nine months ended September 30, 2011 were $12 million and $26.5 million, of which $7 million and $16 million were included in "Other operation and maintenance" on the Statement of Income. In November 2011, PPL Electric filed with the PUC a request for permission to defer $15 to $20 million for future recovery of allowable storm-related costs. At the time PPL Electric seeks recovery of any deferred amount, its claim will be based on the actual costs, net of insurance recoveries. A regulatory asset, for the actual costs net of insurance recoveries, will be recorded at such time as an order is received from the PUC approving deferral of these costs.

In late October 2011, PPL Electric experienced significant damage to its transmission and distribution network from a severe snow storm. The costs associated with the restoration efforts are still being determined and are not included in the amounts disclosed above. PPL Electric will evaluate such costs, when quantified, and will likely file with the PUC for permission to defer certain of the costs incurred to repair the distribution network for future recovery. Costs incurred to repair the transmission network are recoverable through the FERC Formula Rate mechanism which is updated annually.

Transmission Service Charge Adjustment (PPL Electric)

During the three and nine months ended September 30, 2011, PPL Electric recorded a $7 million ($4 million after-tax) charge to "Retail electric" revenue on the Statement of Income to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC. PPL Electric plans to seek recovery with the PUC. However, management cannot assert at the present time that it is probable that the previously recorded regulatory asset will be recovered. The regulatory asset will be reinstated should the PUC approve recovery of these costs. The impact of this charge was not material to any previously reported financial statements and is not expected to be material to the financial statements for the full year of 2011.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

In May 2010, PPL Electric initiated the 2010 Annual Update of its formula rate. In November 2010, a group of municipal customers taking transmission service in PPL Electric's zone filed a preliminary challenge to the update, and in December 2010 they filed a formal challenge. In January 2011, PPL Electric filed a motion to dismiss a number of the challenges and submitted responses to all of the challenges. The group of municipal customers filed answers to PPL Electric's motion to dismiss and its responses to the formal challenge. In August 2011, the FERC issued an order 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 October 2011, the group of municipal customers filed a preliminary challenge to PPL Electric's 2011 Annual Update of its formula rate. PPL Electric will attempt to resolve the issues raised in this preliminary challenge. PPL Electric cannot predict the outcome of this proceeding which remains pending before the FERC.

International Activities (PPL)

U.K. Overhead Electricity Networks

In 2002, for safety reasons, the U.K. Government issued guidance that low voltage overhead electricity networks within three meters horizontal clearance of a building should either be insulated or relocated. This imposed a retroactive requirement on existing assets that were built with lower clearances. In 2008, the U.K. Government determined that the U.K. electricity network should comply with the issued guidance. WPD estimates that the cost of compliance will be approximately $124 million. The projected expenditures in the current regulatory period, April 1, 2010 through March 31, 2015, have been included in allowed revenues, and it is expected that expenditures beyond this five-year period (including WPD Midlands expenditures) will also be included in allowed revenues. The U.K. Government has determined that WPD (South Wales) and WPD Midlands should comply by 2015 and WPD (South West) by 2018.

To improve network reliability, the U.K. Government amended a regulation relating to safety and continuity of supply by adding an obligation which broadly requires, beginning January 31, 2009, network operators to implement a risk-based program to clear trees away from overhead lines. WPD estimates that the cost of compliance will be approximately $205 million over a 25-year period. The projected expenditures in the current regulatory period have been included in allowed revenues under the current price control review, and it is expected that expenditures beyond this five-year period will also be included in allowed revenues.

In addition to the above, WPD Midlands was not in compliance with earlier regulations pertaining to overhead line clearances as of the acquisition date. WPD Midlands expects to incur costs through 2015 to comply with these requirements that are not included in allowed revenues under the current price control review. In the three months ended September 30, 2011, WPD Midlands recorded a liability of $69 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. See Note 8 for additional information.

New U.K. Pricing Model

The electricity distribution subsidiaries of WPD operate under distribution licenses and price controls granted and set by Ofgem for each of the distribution subsidiaries. The price control formula that governs allowed revenue is designed to provide economic incentives to minimize operating, capital and financing costs. The price control formula is normally determined every five years. Ofgem completed its review in December 2009 that became effective April 1, 2010 and will continue through March 31, 2015.

In October 2010, Ofgem announced a pricing model that will be effective for the U.K. electricity distribution sector beginning April 2015. The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure. Key components of the model are: an extension of the price review period from five to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital. At this time, management does not expect the impact of this pricing model to be significant to WPD's operating results.

Public Utilities Disclosure [Line Items]

Regulatory Assets and Liabilities

6. Utility Rate Regulation

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

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

		PPL				PPL Electric
		September 30,		December 31,		September 30,		December 31,
		2011		2010		2011		2010

Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider	$	3		10	$	3		10
	Fuel adjustment clause		10		3
	Other		6		27				8
Total current regulatory assets		$	19	$	85	$	3	$	63

Noncurrent Regulatory Assets:
	Defined benefit plans	$	586	$	592	$	256	$	262
	Taxes recoverable through future rates		270		254		270		254
	Storm costs		132		129		6		7
	Unamortized loss on debt		113		61		80		27
	Interest rate swaps		66		43
	Accumulated cost of removal of utility plant (b)		46		35		46		35
	Coal contracts (c)		14		22
	Other		50		44		5		7
Total noncurrent regulatory assets		$	1,277	$	1,180	$	663	$	592

Current Regulatory Liabilities:
	Coal contracts (c)	$	12	$	46
	Generation supply charge (a)		37			$	37
	ECR		8		12
	PURTA tax		3		10		3	$	10
	DSM		10		10
	Transmission service charge		1		8		1		8
	Other		12		23		5
Total current regulatory liabilities		$	83	$	109	$	46	$	18

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	646	$	623
	Coal contracts (c)		188		213
	Power purchase agreement - OVEC (c)		118		124
	Net deferred tax assets		37		40
	Act 129 compliance rider		13		14	$	13	$	14
	Defined benefit plans		10		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,020	$	1,031	$	13	$	14

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2011		2010		2011		2010		2011		2010

Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)	$	1		5				1	$	1	$	4
	Gas supply clause		5		4	$	5		4
	Fuel adjustment clause		10		3		5		3		5
	Virginia fuel factor				5								5
Total current regulatory assets		$	16	$	22	$	10	$	13	$	6	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	330	$	330	$	213	$	213	$	117	$	117
	Storm costs		126		122		67		65		59		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		66		43		66		43
	Coal contracts (c)		14		22		6		8		8		14
	Other		45		37		17		16		28		21
Total noncurrent regulatory assets		$	614	$	588	$	390	$	367	$	224	$	221

Current Regulatory Liabilities:
		Coal contracts (c)	$	12	$	46	$	8	$	31	$	4	$	15
		ECR		8		12		1				7		12
		DSM		10		10		6		5		4		5
		Other		7		23		5		15		2		8
Total current regulatory liabilities			$	37	$	91	$	20	$	51	$	17	$	40

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	646	$	623	$	284	$	275	$	362	$	348
	Coal contracts (c)			188		213		80		87		108		126
	Power purchase agreement - OVEC (c)			118		124		82		86		36		38
	Net deferred tax assets			37		40		32		34		5		6
	Defined benefit plans			10		10						10		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,007	$	1,017	$	481	$	483	$	526	$	534

(a) PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at September 30, 2011, reflecting the impacts of changes in customer billing cycles, the timing of rate reconciliation filings, the levels of customers choosing alternative energy suppliers and other factors. Because customer rates are designed to collect the costs of PPL Electric's energy purchases to meet its PLR requirements, there is minimal impact on earnings.

(b) The December 31, 2010 balance of accumulated cost of removal of utility plant was reclassified from "Accumulated depreciation - regulated utility plant" to noncurrent "Regulatory assets" on the Balance Sheets. These costs will continue to be included in future rate proceedings.

(c) 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)

Environmental Upgrades

In order to achieve compliance with new and pending federal EPA regulations including CSAPR, National Ambient Air Quality Standards and the MACT rule, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses, as incurred. The ECR plans detail upgrades that will be made to certain of their coal-fired generating stations to continue to be compliant with EPA regulations.

LG&E requested $1.4 billion to modernize the sulfur dioxide scrubbers at the Mill Creek generating station as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at Mill Creek and for Unit 1 at Trimble County. In its KPSC application, LG&E estimated the impact on rates to LG&E's electric customers to be an increase of 2.3% in 2012, growing to an increase of 19.2% by 2016. KU requested $1.1 billion for upgrades that include fabric-filter baghouse systems for increased particulate and mercury control on units at the E.W. Brown and Ghent generating stations and the conversion of a wet storage facility to a dry landfill at the E.W. Brown generating station. In its KPSC application, KU estimated the impact on rates to KU's electric customers to be an increase of 1.5% in 2012, growing to an increase of 12.2% by 2016.

Certain parties have been granted intervenor status in the ECR proceedings. The KPSC issued a procedural schedule under which data discovery is expected to continue into the fourth quarter. A KPSC order is anticipated to be issued in December 2011. LG&E and KU cannot predict the outcome of these proceedings.

IRP

IRP regulations in Kentucky require major utilities to make triennial IRP filings with the KPSC. In April 2011, LG&E and KU filed their 2011 joint IRP with the KPSC. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information. In May 2011, the KPSC issued a procedural schedule and data discovery will continue through the fourth quarter. Pursuant to a December 2008 Order, KU filed the 2011 joint IRP with the VSCC in September 2011, with certain supplemental information as required by this Order. The IRP assumes approximately 500 MW of peak demand reductions by 2017 through existing or expanded DSM or energy efficiency programs. Implementation of the major findings of the IRP is subject to further analysis and decision-making and further regulatory approvals.

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 station site. KU will own a 78% undivided interest, and LG&E will own a 22% undivided interest, in the new NGCC. In addition, LG&E and KU also requested approval to purchase three additional natural gas combustion turbines from Bluegrass Generation Company, L.L.C. that are expected to provide up to 495 MW of peak generation supply (the Bluegrass Plant). In conjunction with these developments, at the end of 2015 LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run station and also coal-fired generating units at KU's Tyrone and Green River stations. These generating stations represent 797 MW of combined summer capacity.

LG&E and KU anticipate that the NGCC construction and Bluegrass Plant acquisition 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. Formal requests for recovery of the costs associated with the NGCC and Bluegrass Plant acquisition were not included in the CPCN filing with the KPSC, but are expected to be included in a future base rate case filing. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery, but no hearing, scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

DSM/Energy Efficiency

In April 2011, LG&E and KU filed a DSM application to expand existing energy efficiency programs and implement new energy efficiency programs. Discovery and evidentiary phases have been completed and a KPSC order is anticipated during the fourth quarter of 2011. Any increase in rates will not be implemented until an order is issued by the KPSC.

PPL's Acquisition of LKE

In September 2010, the KPSC approved a settlement agreement among PPL and all of the intervening parties to PPL's joint application to the KPSC for approval of its acquisition of ownership and control of LKE, LG&E and KU. In the settlement agreement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013. Under the terms of the settlement, LG&E and KU retain the right to seek KPSC approval for the deferral of "extraordinary and uncontrollable costs," such as significant storm restoration costs, if incurred. Additionally, interim rate adjustments will continue to be permissible during that period for existing recovery mechanisms such as the ECR and DSM.

Storm Costs (PPL, LKE and LG&E)

In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011, requesting approval of a regulatory asset recorded to defer, for future recovery, $7 million in incremental operation and maintenance expenses related to the storm restoration. The KPSC has issued a procedural schedule for discovery relating to the application during the fourth quarter.

Virginia Activities (PPL, LKE and KU)

Rate Case

In April 2011, KU filed an application with the VSCC requesting an annual increase in electric base rates for its Virginia jurisdictional customers of $9 million, or 14%. The proposed increase reflected a rate of return on rate base of 8%, based on a return on equity of 11%, inclusive of expenditures to complete TC2, all new sulfur dioxide scrubbers, recovery over five years of a 2009 storm regulatory asset and various other adjustments to revenue and expenses for the test year ended December 31, 2010. In September 2011, a settlement stipulation was reached between KU and the VSCC Staff and filed with the VSCC for consideration. In October 2011, the VSCC approved the stipulation with two modifications that were accepted by KU. The VSCC issued an Order closing the proceeding in October 2011. The approved annual revenue increase is $7 million with new base rates effective November 1, 2011.

Levelized Fuel Factor

In February 2011, KU filed an application with the VSCC seeking approval of an increase in its fuel cost factor beginning with service rendered in April 2011. In March 2011, a hearing was held on KU's requested fuel factor and an Order was issued approving a revised fuel factor to be in effect beginning with service rendered on and after April 1, 2011, with recovery of the regulatory asset for prior period under-recoveries over a three-year period.

Storm Costs

In December 2009, a major snowstorm hit KU's Virginia service area causing approximately 30,000 customer outages. During the normal 2009 Virginia Annual Information Filing (AIF), KU requested that the VSCC establish a regulatory asset and defer for future recovery $6 million in incremental operation and maintenance expenses related to the storm restoration. In March 2011, the VSCC Staff issued its report on KU's 2009 AIF stating that it considered this storm damage to be extraordinary, non-recurring and material to KU. The Staff Report also recommended establishing a regulatory asset for these costs, with recovery over a five-year period upon approval in the next base rate case. In March 2011, a regulatory asset of $6 million was established for actual costs incurred. In June 2011, the VSCC issued an Order approving the recommendations contained in the Staff Report.

Pennsylvania Activities

(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania electric utilities to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. Utilities not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, Electric Distribution Companies (EDCs) must develop and 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 2011 and 3.0% by 2013, and reduced peak demand of 4.5% for the 100 hours of highest demand by 2013. To date, PPL Electric has met the 2011 requirement, subject to the PUC's verification. 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. The plan includes 14 programs, all of which are voluntary for customers. The plan includes a proposed rate mechanism for recovery of all costs incurred by PPL Electric to implement the plan. In September 2010, PPL Electric filed its Program Year 1 Annual Report and Process Evaluation Report. PPL Electric also filed a petition requesting permission to modify two components of its EE&C Plan. The PUC issued its Final Order in January 2011, approving the changes proposed by PPL Electric and directing PPL Electric to re-file its plan to reflect all changes made since its initial approval. In February 2011, PPL Electric filed the changes to its plan and in May 2011, the PUC approved those changes.

Act 129 also requires installation of smart meters for new construction, upon the request of consumers at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs will be able to recover the costs of providing smart metering technology. In August 2009, PPL Electric filed its proposed smart meter technology procurement and installation plan with the PUC. All of PPL Electric's metered customers currently have smart meters installed at their service locations, and PPL Electric's current advanced metering technology generally satisfies the requirements of Act 129 and does not need to be replaced. In June 2010, the PUC entered its order approving PPL Electric's smart meter plan with several modifications. In compliance with the Order, in the third quarter of 2010, PPL Electric submitted a revised plan with a cost estimate of $38 million to be incurred over a five-year period, beginning in 2009, and filed a rider to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of its smart meter program. In August 2011, PPL Electric filed with the PUC an annual report describing the actions it is taking under its smart meter plan in 2011 and will take in 2012. PPL Electric also submitted proposed Smart Meter Rider charges to be effective January 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 up 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.

Under Act 129, the DSP competitive procurement plan must ensure adequate and reliable service "at least cost to customers" over time. Act 129 grants the PUC authority to extend long-term power contracts up to 20 years, if necessary, to achieve the "least cost" standard. The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric has begun purchasing under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

PUC Investigation of Retail Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market which will be conducted in two phases. Phase one will address the status of the current retail market and explore potential changes. Questions promulgated by the PUC for this phase of the investigation focus primarily on default service issues. In June 2011, interested parties filed comments and the PUC held a hearing in this phase of the investigation. In July 2011, the PUC entered an order initiating phase two of the investigation which will study how best to address issues identified by the PUC as being most relevant to improving the current retail electricity market. The PUC issued a tentative order in October 2011 addressing issues associated with the timing and various other details of EDCs' default service procurement plans. Parties will have an opportunity to comment on that tentative order. The PUC also has scheduled a hearing in this phase of the investigation in November 2011. It is likely that investigation will not be completed before the end of the year. 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 that would authorize the PUC to approve regulatory procedures and mechanisms to provide for more timely recovery of a utility's costs. Those procedures and mechanisms include, but are not limited to, the use of a fully projected test year and an automatic adjustment clause to recover certain capital costs and related operating expenses. In October 2011, the legislation was passed by the Pennsylvania House of Representatives. It will now be considered by the Pennsylvania Senate. PPL Electric is working with other stakeholders to support passage of this legislation.

Unamortized Loss on Debt

As further discussed in Note 7, in July 2011 PPL Electric redeemed Senior Secured Bonds for $458 million, plus accrued interest. The redemption premium and the unamortized financing costs of $59 million were recorded as a regulatory asset which will be amortized over the life of the replacement debt.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during the three and nine months ended September 30, 2011 resulting in total restoration costs of $34 million and $59 million, of which $23 million and $39 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms has exceeded policy limits. Probable insurance recoveries recorded during the three and nine months ended September 30, 2011 were $12 million and $26.5 million, of which $7 million and $16 million were included in "Other operation and maintenance" on the Statement of Income. In November 2011, PPL Electric filed with the PUC a request for permission to defer $15 to $20 million for future recovery of allowable storm-related costs. At the time PPL Electric seeks recovery of any deferred amount, its claim will be based on the actual costs, net of insurance recoveries. A regulatory asset, for the actual costs net of insurance recoveries, will be recorded at such time as an order is received from the PUC approving deferral of these costs.

In late October 2011, PPL Electric experienced significant damage to its transmission and distribution network from a severe snow storm. The costs associated with the restoration efforts are still being determined and are not included in the amounts disclosed above. PPL Electric will evaluate such costs, when quantified, and will likely file with the PUC for permission to defer certain of the costs incurred to repair the distribution network for future recovery. Costs incurred to repair the transmission network are recoverable through the FERC Formula Rate mechanism which is updated annually.

Transmission Service Charge Adjustment (PPL Electric)

During the three and nine months ended September 30, 2011, PPL Electric recorded a $7 million ($4 million after-tax) charge to "Retail electric" revenue on the Statement of Income to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC. PPL Electric plans to seek recovery with the PUC. However, management cannot assert at the present time that it is probable that the previously recorded regulatory asset will be recovered. The regulatory asset will be reinstated should the PUC approve recovery of these costs. The impact of this charge was not material to any previously reported financial statements and is not expected to be material to the financial statements for the full year of 2011.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

In May 2010, PPL Electric initiated the 2010 Annual Update of its formula rate. In November 2010, a group of municipal customers taking transmission service in PPL Electric's zone filed a preliminary challenge to the update, and in December 2010 they filed a formal challenge. In January 2011, PPL Electric filed a motion to dismiss a number of the challenges and submitted responses to all of the challenges. The group of municipal customers filed answers to PPL Electric's motion to dismiss and its responses to the formal challenge. In August 2011, the FERC issued an order 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 October 2011, the group of municipal customers filed a preliminary challenge to PPL Electric's 2011 Annual Update of its formula rate. PPL Electric will attempt to resolve the issues raised in this preliminary challenge. PPL Electric cannot predict the outcome of this proceeding which remains pending before the FERC.

International Activities (PPL)

U.K. Overhead Electricity Networks

In 2002, for safety reasons, the U.K. Government issued guidance that low voltage overhead electricity networks within three meters horizontal clearance of a building should either be insulated or relocated. This imposed a retroactive requirement on existing assets that were built with lower clearances. In 2008, the U.K. Government determined that the U.K. electricity network should comply with the issued guidance. WPD estimates that the cost of compliance will be approximately $124 million. The projected expenditures in the current regulatory period, April 1, 2010 through March 31, 2015, have been included in allowed revenues, and it is expected that expenditures beyond this five-year period (including WPD Midlands expenditures) will also be included in allowed revenues. The U.K. Government has determined that WPD (South Wales) and WPD Midlands should comply by 2015 and WPD (South West) by 2018.

To improve network reliability, the U.K. Government amended a regulation relating to safety and continuity of supply by adding an obligation which broadly requires, beginning January 31, 2009, network operators to implement a risk-based program to clear trees away from overhead lines. WPD estimates that the cost of compliance will be approximately $205 million over a 25-year period. The projected expenditures in the current regulatory period have been included in allowed revenues under the current price control review, and it is expected that expenditures beyond this five-year period will also be included in allowed revenues.

In addition to the above, WPD Midlands was not in compliance with earlier regulations pertaining to overhead line clearances as of the acquisition date. WPD Midlands expects to incur costs through 2015 to comply with these requirements that are not included in allowed revenues under the current price control review. In the three months ended September 30, 2011, WPD Midlands recorded a liability of $69 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. See Note 8 for additional information.

New U.K. Pricing Model

The electricity distribution subsidiaries of WPD operate under distribution licenses and price controls granted and set by Ofgem for each of the distribution subsidiaries. The price control formula that governs allowed revenue is designed to provide economic incentives to minimize operating, capital and financing costs. The price control formula is normally determined every five years. Ofgem completed its review in December 2009 that became effective April 1, 2010 and will continue through March 31, 2015.

In October 2010, Ofgem announced a pricing model that will be effective for the U.K. electricity distribution sector beginning April 2015. The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure. Key components of the model are: an extension of the price review period from five to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital. At this time, management does not expect the impact of this pricing model to be significant to WPD's operating results.

Public Utilities Disclosure [Line Items]