Rates and Regulatory Matters [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
		June 30,		December 31,		June 30,		December 31,
		2011		2010		2011		2010

Current Regulatory Assets:
	Generation supply charge			$	45			$	45
	Universal service rider	$	6		10	$	6		10
	Other		19		30		4		8
Total current regulatory assets		$	25	$	85	$	10	$	63

Noncurrent Regulatory Assets:
	Defined benefit plans	$	588	$	592	$	258	$	262
	Taxes recoverable through future rates		268		254		268		254
	Storm costs		128		129		7		7
	Unamortized loss on debt		58		61		25		27
	Interest rate swaps		44		43
	Accumulated cost of removal of utility plant (a)		40		35		40		35
	Coal contracts (b)		16		22
	Other		58		44		12		7
Total noncurrent regulatory assets		$	1,200	$	1,180	$	610	$	592

Current Regulatory Liabilities:
	Coal contracts (b)	$	23	$	46
	Generation supply charge		16			$	16
	ECR		9		12
	PURTA tax		5		10		5	$	10
	Transmission service charge				8				8
	Other		24		33		2
Total current regulatory liabilities		$	77	$	109	$	23	$	18

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	638	$	623
	Coal contracts (b)		197		213
	Power purchase agreement - OVEC (b)		120		124
	Net deferred tax assets		36		40
	Act 129 compliance rider		15		14	$	15	$	14
	Defined benefit plans		10		10
	Other		7		7
Total noncurrent regulatory liabilities		$	1,023	$	1,031	$	15	$	14

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

Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (b)	$	3		5	$	1		1	$	2	$	4
	Gas supply clause		5		4		5		4
	Fuel adjustment clause		7		3		5		3		2
	Virginia fuel factor				5								5
Total current regulatory assets		$	15	$	22	$	11	$	13	$	4	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	330	$	330	$	213	$	213	$	117	$	117
	Storm costs		121		122		61		65		60		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		44		43		44		43
	Coal contracts (b)		16		22		6		8		10		14
	Other		46		37		18		16		28		21
Total noncurrent regulatory assets		$	590	$	588	$	363	$	367	$	227	$	221

Current Regulatory Liabilities:
		Coal contracts (b)	$	23	$	46	$	15	$	31	$	8	$	15
		ECR		9		12						9		12
		Other		22		33		14		20		8		13
Total current regulatory liabilities			$	54	$	91	$	29	$	51	$	25	$	40

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	638	$	623	$	281	$	275	$	357	$	348
	Coal contracts (b)			197		213		83		87		114		126
	Power purchase agreement - OVEC (b)			120		124		83		86		37		38
	Net deferred tax assets			36		40		31		34		5		6
	Defined benefit plans			10		10						10		10
	Other			7		7		2		1		5		6
Total noncurrent regulatory liabilities			$	1,008	$	1,017	$	480	$	483	$	528	$	534

(a) 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.

(b) 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 and the MACT rule, in June 2011, LG&E and KU filed an ECR plan with the KPSC requesting approval to install environmental upgrades for their coal-fired plants and recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses, as incurred. The ECR plan details upgrades that will be made to certain of their coal-fired generating stations to continue to be compliant with EPA regulations. Additionally, LG&E and KU notified the KPSC that a likely further effect of the new requirements is to accelerate the retirement of three other older coal-fired plants requiring LG&E and KU to replace the lost energy supplied by those plants.

LG&E requested $1.4 billion to modernize the 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% in 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% in 2016.

Certain parties have submitted interventions 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.

Integrated Resource Planning

Integrated Resource Planning (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 third quarter. Pursuant to a December 2008 Order, KU will file the 2011 joint IRP with the VSCC by September 2011, with certain supplemental information as required by this Order. Impending environmental regulation could result in the retirements of older, smaller coal-fired units and therefore the IRP assumes approximately 800 MW of potential retirements of coal-fired capacity in 2016 and replacement by combined-cycle gas units. In addition, 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.

Demand-Side Management/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. LG&E and KU requested new DSM rates to become effective on May 13, 2011. On May 10, 2011, the KPSC issued an Order suspending the proposed rates for five months until October 12, 2011. On May 20, 2011, the KPSC issued an Order establishing a procedural schedule for discovery and intervenor testimony, but the KPSC did not schedule a hearing in the proceeding.

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.

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 reflects 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 flue gas desulfurization controls, 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. While KU cannot predict the amount of the allowed increase, it expects the new rates to go into effect in January 2012.

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 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. 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.

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 (four 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. 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. The legislation is now before the full Pennsylvania House of Representatives. PPL Electric is working with other stakeholders to support passage of this legislation.

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. 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 $126 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 a new 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 $208 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 (East Midlands) and WPD (West Midlands) were not in compliance with earlier regulations pertaining to overhead line clearances as of the acquisition date. WPD (East Midlands) and WPD (West Midlands) expect to incur costs through 2015 to comply with these requirements that are not included in allowed revenues under the current price control review. Management is in the process of assessing and quantifying this exposure as a result of the acquisition.

New U.K. Pricing Model

The electricity distribution subsidiaries of PPL WW and PPL WEM operate under distribution licenses and price controls granted and set by Ofgem for each of their 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 new 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.

Rates and Regulatory Matters [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
		June 30,		December 31,		June 30,		December 31,
		2011		2010		2011		2010

Current Regulatory Assets:
	Generation supply charge			$	45			$	45
	Universal service rider	$	6		10	$	6		10
	Other		19		30		4		8
Total current regulatory assets		$	25	$	85	$	10	$	63

Noncurrent Regulatory Assets:
	Defined benefit plans	$	588	$	592	$	258	$	262
	Taxes recoverable through future rates		268		254		268		254
	Storm costs		128		129		7		7
	Unamortized loss on debt		58		61		25		27
	Interest rate swaps		44		43
	Accumulated cost of removal of utility plant (a)		40		35		40		35
	Coal contracts (b)		16		22
	Other		58		44		12		7
Total noncurrent regulatory assets		$	1,200	$	1,180	$	610	$	592

Current Regulatory Liabilities:
	Coal contracts (b)	$	23	$	46
	Generation supply charge		16			$	16
	ECR		9		12
	PURTA tax		5		10		5	$	10
	Transmission service charge				8				8
	Other		24		33		2
Total current regulatory liabilities		$	77	$	109	$	23	$	18

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	638	$	623
	Coal contracts (b)		197		213
	Power purchase agreement - OVEC (b)		120		124
	Net deferred tax assets		36		40
	Act 129 compliance rider		15		14	$	15	$	14
	Defined benefit plans		10		10
	Other		7		7
Total noncurrent regulatory liabilities		$	1,023	$	1,031	$	15	$	14

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

Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (b)	$	3		5	$	1		1	$	2	$	4
	Gas supply clause		5		4		5		4
	Fuel adjustment clause		7		3		5		3		2
	Virginia fuel factor				5								5
Total current regulatory assets		$	15	$	22	$	11	$	13	$	4	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	330	$	330	$	213	$	213	$	117	$	117
	Storm costs		121		122		61		65		60		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		44		43		44		43
	Coal contracts (b)		16		22		6		8		10		14
	Other		46		37		18		16		28		21
Total noncurrent regulatory assets		$	590	$	588	$	363	$	367	$	227	$	221

Current Regulatory Liabilities:
		Coal contracts (b)	$	23	$	46	$	15	$	31	$	8	$	15
		ECR		9		12						9		12
		Other		22		33		14		20		8		13
Total current regulatory liabilities			$	54	$	91	$	29	$	51	$	25	$	40

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	638	$	623	$	281	$	275	$	357	$	348
	Coal contracts (b)			197		213		83		87		114		126
	Power purchase agreement - OVEC (b)			120		124		83		86		37		38
	Net deferred tax assets			36		40		31		34		5		6
	Defined benefit plans			10		10						10		10
	Other			7		7		2		1		5		6
Total noncurrent regulatory liabilities			$	1,008	$	1,017	$	480	$	483	$	528	$	534

(a) 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.

(b) 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 and the MACT rule, in June 2011, LG&E and KU filed an ECR plan with the KPSC requesting approval to install environmental upgrades for their coal-fired plants and recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses, as incurred. The ECR plan details upgrades that will be made to certain of their coal-fired generating stations to continue to be compliant with EPA regulations. Additionally, LG&E and KU notified the KPSC that a likely further effect of the new requirements is to accelerate the retirement of three other older coal-fired plants requiring LG&E and KU to replace the lost energy supplied by those plants.

LG&E requested $1.4 billion to modernize the 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% in 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% in 2016.

Certain parties have submitted interventions 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.

Integrated Resource Planning

Integrated Resource Planning (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 third quarter. Pursuant to a December 2008 Order, KU will file the 2011 joint IRP with the VSCC by September 2011, with certain supplemental information as required by this Order. Impending environmental regulation could result in the retirements of older, smaller coal-fired units and therefore the IRP assumes approximately 800 MW of potential retirements of coal-fired capacity in 2016 and replacement by combined-cycle gas units. In addition, 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.

Demand-Side Management/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. LG&E and KU requested new DSM rates to become effective on May 13, 2011. On May 10, 2011, the KPSC issued an Order suspending the proposed rates for five months until October 12, 2011. On May 20, 2011, the KPSC issued an Order establishing a procedural schedule for discovery and intervenor testimony, but the KPSC did not schedule a hearing in the proceeding.

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.

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 reflects 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 flue gas desulfurization controls, 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. While KU cannot predict the amount of the allowed increase, it expects the new rates to go into effect in January 2012.

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 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. 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.

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 (four 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. 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. The legislation is now before the full Pennsylvania House of Representatives. PPL Electric is working with other stakeholders to support passage of this legislation.

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. 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 $126 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 a new 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 $208 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 (East Midlands) and WPD (West Midlands) were not in compliance with earlier regulations pertaining to overhead line clearances as of the acquisition date. WPD (East Midlands) and WPD (West Midlands) expect to incur costs through 2015 to comply with these requirements that are not included in allowed revenues under the current price control review. Management is in the process of assessing and quantifying this exposure as a result of the acquisition.

New U.K. Pricing Model

The electricity distribution subsidiaries of PPL WW and PPL WEM operate under distribution licenses and price controls granted and set by Ofgem for each of their 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 new 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.

Rates and Regulatory Matters [Line Items]