Utility Rate Regulation

12 Months Ended

Dec. 31, 2011

PPL Corp [Member]

Public Utilities Disclosure [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.

(PPL, LKE, LG&E and KU)

LG&E issubject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECRmechanism. As such, regulatory assets generally earn a return.

As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at the acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect the original contracted prices for these contracts.

(PPL, LKE and KU)

KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.

KU's rates tomunicipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.

(PPL and PPL Electric)

PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(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
		2011		2010		2011		2010
Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider				10				10
	Gas supply clause	$	6		4
	Fuel adjustment clause		3		3
	Other				23				8
Total current regulatory assets		$	9	$	85			$	63
Noncurrent Regulatory Assets:
	Defined benefit plans	$	615	$	592	$	276	$	262
	Taxes recoverable through future rates		289		254		289		254
	Storm costs		154		129		31		7
	Unamortized loss on debt		110		61		77		27
	Interest rate swaps		69		43
	Accumulated cost of removal of utility plant (b)		53		35		53		35
	Coal contracts (c)		11		22
	AROs		18		9
	Other		30		35		3		7
Total noncurrent regulatory assets		$	1,349	$	1,180	$	729	$	592

Current Regulatory Liabilities:
	Coal contracts (c)			$	46
	Generation supply charge (a)	$	42			$	42
	ECR		7		12
	PURTA tax				10			$	10
	Gas supply clause		6		9
	Transmission service charge		2		8		2		8
	Other		16		24		9
Total current regulatory liabilities		$	73	$	109	$	53	$	18
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	651	$	623
	Coal contracts (c)		180		213
	Power purchase agreement - OVEC (c)		116		124
	Net deferred tax assets		39		40
	Act 129 compliance rider		7		14	$	7	$	14
	Defined benefit plans		9		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,010	$	1,031	$	7	$	14

		LKE				LG&E				KU
		2011		2010		2011		2010		2011		2010
Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)				5				1			$	4
	Gas supply clause	$	6		4	$	6		4
	Fuel adjustment clause		3		3		3		3
	Virginia fuel factor				5								5
Total current regulatory assets		$	9	$	22	$	9	$	13			$	9
Noncurrent Regulatory Assets:
	Defined benefit plans	$	339	$	330	$	225	$	213	$	114	$	117
	Storm costs		123		122		66		65		57		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		69		43		69		43
	Coal contracts (c)		11		22		5		8		6		14
	AROs		18		9		11		7		7		2
	Other		27		28		6		9		21		19
Total noncurrent regulatory assets		$	620	$	588	$	403	$	367	$	217	$	221

Current Regulatory Liabilities:
		Coal contracts (c)			$	46			$	31			$	15
		ECR	$	7		12					$	7		12
		Gas supply clause		6		9	$	6		9
		Other		7		24		4		11		3		13
Total current regulatory liabilities			$	20	$	91	$	10	$	51	$	10	$	40
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	651	$	623	$	286	$	275	$	365	$	348
	Coal contracts (c)			180		213		78		87		102		126
	Power purchase agreement - OVEC (c)			116		124		80		86		36		38
	Net deferred tax assets			39		40		31		34		8		6
	Defined benefit plans			9		10						9		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,003	$	1,017	$	478	$	483	$	525	$	534

(a)       PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at December 31, 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 Assets and Liabilities

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

(PPL and PPL Electric)

Generation Supply Charge

The generation supply charge is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLRcustomers who receive basic generation supply service.The recovery includes charges for generation supply (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.

Universal Service Rider (USR)

PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers. Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP). OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills. This program is funded by residential customers and administered by community-based organizations. Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services. The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services. The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules. The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

PURTA Tax

In December 2009, PPL Electric reached a settlement with the Pennsylvania Department of Revenue related to the appeal of its 1997 PURTA tax assessments that resulted in a reduction in PURTA tax. Substantially all of the regulatory liability was refunded to customers in 2011 pursuant to PUC regulations.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric filed its energy efficiency and conservation plan in July 2009. The plan was approved by PUC Order in October 2009. The Order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May31, 2013. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or collected at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLRcustomers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

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

Defined Benefit Plans

Recoverable costs of defined benefit plans represent the portion of unrecognized transition obligation, prior service cost and net actuarial losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured. Of the regulatory asset and liability balances recorded, the following costs of $44 million for PPL, $13 million for PPL Electric, $31 million for LKE, $21 million for LG&E and $10 millionfor KU are expected to be amortized into net periodic defined benefit costs in 2012. All costs will be amortized over the average service lives of plan participants.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes. Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenses in a base rate case.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2029 for PPL Electric. Such costs are being amortized through 2035for LG&E and 2036 for PPL, LKE and KU.

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 and will be amortized over the life of the replacement debt.

Accumulated Cost of Removal

LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. See Note 1 for additional information.

PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the deferral of costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.

(PPL, LKE, LG&E and KU)

ECR

Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is recovered within 12 months. LG&E and KU are authorized to receive a 10.63% return on equity for the 2005, 2006 and 2009 compliance plans and a 10.10% return on projects associated with the 2011 compliance plan.

Coal Contracts

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current marketprices and offsets to regulatory liabilitiesfor those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjustedquarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indicesbetween the shareholders and the customers during each performance-based rate year (12 months ending October 31).The regulatory assets or liabilitiesrepresent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.

Fuel Adjustments

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs,from the costs embedded in base ratesare adjusted in LG&E's and KU's rates. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and,to the extent appropriate, reestablish the fuel charge included in base rates.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are recovered within 12 months.

Interest Rate Swaps

(PPL, LKE and LG&E)

Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an Order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures through 2033. Amortization of the gain/loss related to the terminated swap contract is recovered through 2035 as approved by the KPSC.

(LKE and LG&E)

In the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflect the reclassification of its ineffective swaps and terminated swap to regulatory assets based on an Order from the KPSC in the 2010 rate case whereby the cost of LG&E's terminated swap was allowed to be recovered in base rates. Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within other comprehensive income and common equity. The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.

(PPL, LKE, LG&E and KU)

AROs

As noted in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&Eand ARO liability.

DSM

DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM rate mechanism that provides for concurrent recovery of DSM costs and also provides an incentive for implementing DSM programs. The provision also allows LG&E and KU to recover revenues from lost sales associated with the DSM programs up to the earlier of three years or implementation of new base rates which reflect that load reduction.In addition, with the KPSC Order issued in November 2011, the DSM mechanism now includes a provision to earn a return of and on capital investment for DSM programs. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanism.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's fair values of the OVEC power purchase agreement were recorded on the balance sheets with offsetsto regulatory liabilities. Theregulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition, and have no impact on rate making.

Regulatory Liability associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized. For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.

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 the CSAPR, National Ambient Air Quality Standards andMATS, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants 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 plant as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at the Mill Creek generating plant and on Unit 1 at the Trimble County generating plant. KU requested $1.1 billion to upgrade fabric-filter baghouse systems for increased particulate and mercury control on all units at the E.W. Brown and Ghent generating plants and to convert a wet storage facility to a dry landfill at the E.W. Brown generating plant.

InNovember 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans.  The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings.  The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction.  The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings.  See Note 15 for additional information.

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 concluded during the fourth quarter. 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. LG&E and KU are awaiting the KPSC Staff report, which will close this proceeding.

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 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 plant and also onecoal-fired generating unit at KU's Tyrone plantand two at KU's Green Riverplant. 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. Formal requests for recovery of the costs associated with the NGCC construction and theacquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

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.

In connection with the 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 is in excess of 10.75%, fifty percent of the excess amount will be deferred as a regulatory liability and ultimately returned to customers.  The first ASSD filing will be made by April 1, 2012 based on the 2011 calendar year. Based upon 2011 earnings and their 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 as of December 31, 2011. 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.

Independent Transmission Operators

LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approvalto transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is required, and an application requesting approval was filed in January 2012.

Storm Costs

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 2011requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.

In September 2009, the KPSC approved the deferral of $44 million and $57 million for LG&E and KUof costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million and $2 million for LG&E and KU of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assetsover a ten-year amortization period ending July 2020.

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 concluded in September 2011. In November 2011, the KPSC approved the application as filed. The new rates were effective December 30, 2011.

Virginia Activities(PPL, LKE and KU)

IRP

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 provides historical and projected demand, resource and financial data, and other operating performance and system information and 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.

Virginia 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 amortization 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, and KU began recovering these costs over a five-year amortization period ending October 2016.

Pennsylvania Activities(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. EDCs not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). 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 (up to a maximum of $250 million) by PPL Electric to implement the plan. Such costs include direct and indirect charges, including design, general and administrative costs and applicable state evaluator costs, and are being recovered over the period from January 1, 2010 through May 31, 2013. The costs are recovered through the Act 129 Compliance Rider from all customers who receive distribution service. The program contains a reconciliation mechanism whereby any over- or under-recovery from customers will be refunded or collected at the end of the program. 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. PPL Electric filed its Program Year 2 Annual Report and Process Evaluation Report in November 2011. In February 2012, PPL Electric filed a petition with the PUC requesting permission to implement additional changes to its EE&C Plan. Other parties have 30 days to file comments to this petition; PPL Electric has 20 days to file reply comments.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

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 continues to procure power for its PLR obligations under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

Smart Meter Rider

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs 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. 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 its Section 1307(e)cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments. The SMR,which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year. 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 its planned actions for 2012. PPL Electric also submitted revisedSMR charges which became effective January 1, 2012.

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 current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focused 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 to 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 filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. 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. Parties filed comments to that tentative order. 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. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future 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. In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvements charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 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 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.

In 2007, based on PUC approval, a regulatory asset of $12 million was established for actual costs incurred associated with severe ice storms that occurred in January 2005. Recovery began in January 2008 and will continue through August 2015.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism. The tariff allows for recovery of actual transmission costs incurred, a return on transmission plant placed in service and an incentive return, including a return on construction work in progress, on the Susquehanna-Roseland transmission line project. The tariff utilizes actual costs from the most recent FERC Form No. 1 to set the rate for the current year billing to customers, including a true-up to adjust for actual costs in the subsequent year's FERC Form No. 1. The annual update of the rate is implemented automatically without requiring specific approval by the FERC before going into effect. PPL Electric accrues or defers revenues applicable to any estimated true-up of this formula-based rate.

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 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 the 2011 Annual Update of its formula rate. In October 2011, the group of municipal customers filed a preliminary challenge to the update.PPL Electric was not able to resolve the issues that were raised in this preliminary challenge and the group of municipal customers filed a formal challenge.PPL Electric filed a response to that formal challenge and the group of municipal customers filed an answer to that response.PPL Electric cannot predict the outcome of these two proceedings, which remain pending before the FERC.

In March 2012, PPL Electric plans to file 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 sheet. 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.

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 $120 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) should comply 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 $198 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 2011, WPD Midlands recorded a liability of $68 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. The balance at December 31, 2011 was $57 million.

Ofgem Review of Line Loss Calculation

WPD has a $170 million liabilityrecorded at December 31, 2011, calculated in accordance with an 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; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.

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.

PPL Electric [Member]

Public Utilities Disclosure [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.

(PPL, LKE, LG&E and KU)

LG&E issubject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECRmechanism. As such, regulatory assets generally earn a return.

As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at the acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect the original contracted prices for these contracts.

(PPL, LKE and KU)

KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.

KU's rates tomunicipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.

(PPL and PPL Electric)

PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(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
		2011		2010		2011		2010
Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider				10				10
	Gas supply clause	$	6		4
	Fuel adjustment clause		3		3
	Other				23				8
Total current regulatory assets		$	9	$	85			$	63
Noncurrent Regulatory Assets:
	Defined benefit plans	$	615	$	592	$	276	$	262
	Taxes recoverable through future rates		289		254		289		254
	Storm costs		154		129		31		7
	Unamortized loss on debt		110		61		77		27
	Interest rate swaps		69		43
	Accumulated cost of removal of utility plant (b)		53		35		53		35
	Coal contracts (c)		11		22
	AROs		18		9
	Other		30		35		3		7
Total noncurrent regulatory assets		$	1,349	$	1,180	$	729	$	592

Current Regulatory Liabilities:
	Coal contracts (c)			$	46
	Generation supply charge (a)	$	42			$	42
	ECR		7		12
	PURTA tax				10			$	10
	Gas supply clause		6		9
	Transmission service charge		2		8		2		8
	Other		16		24		9
Total current regulatory liabilities		$	73	$	109	$	53	$	18
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	651	$	623
	Coal contracts (c)		180		213
	Power purchase agreement - OVEC (c)		116		124
	Net deferred tax assets		39		40
	Act 129 compliance rider		7		14	$	7	$	14
	Defined benefit plans		9		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,010	$	1,031	$	7	$	14

		LKE				LG&E				KU
		2011		2010		2011		2010		2011		2010
Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)				5				1			$	4
	Gas supply clause	$	6		4	$	6		4
	Fuel adjustment clause		3		3		3		3
	Virginia fuel factor				5								5
Total current regulatory assets		$	9	$	22	$	9	$	13			$	9
Noncurrent Regulatory Assets:
	Defined benefit plans	$	339	$	330	$	225	$	213	$	114	$	117
	Storm costs		123		122		66		65		57		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		69		43		69		43
	Coal contracts (c)		11		22		5		8		6		14
	AROs		18		9		11		7		7		2
	Other		27		28		6		9		21		19
Total noncurrent regulatory assets		$	620	$	588	$	403	$	367	$	217	$	221

Current Regulatory Liabilities:
		Coal contracts (c)			$	46			$	31			$	15
		ECR	$	7		12					$	7		12
		Gas supply clause		6		9	$	6		9
		Other		7		24		4		11		3		13
Total current regulatory liabilities			$	20	$	91	$	10	$	51	$	10	$	40
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	651	$	623	$	286	$	275	$	365	$	348
	Coal contracts (c)			180		213		78		87		102		126
	Power purchase agreement - OVEC (c)			116		124		80		86		36		38
	Net deferred tax assets			39		40		31		34		8		6
	Defined benefit plans			9		10						9		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,003	$	1,017	$	478	$	483	$	525	$	534

(a)       PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at December 31, 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 Assets and Liabilities

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

(PPL and PPL Electric)

Generation Supply Charge

The generation supply charge is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLRcustomers who receive basic generation supply service.The recovery includes charges for generation supply (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.

Universal Service Rider (USR)

PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers. Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP). OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills. This program is funded by residential customers and administered by community-based organizations. Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services. The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services. The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules. The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

PURTA Tax

In December 2009, PPL Electric reached a settlement with the Pennsylvania Department of Revenue related to the appeal of its 1997 PURTA tax assessments that resulted in a reduction in PURTA tax. Substantially all of the regulatory liability was refunded to customers in 2011 pursuant to PUC regulations.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric filed its energy efficiency and conservation plan in July 2009. The plan was approved by PUC Order in October 2009. The Order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May31, 2013. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or collected at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLRcustomers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

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

Defined Benefit Plans

Recoverable costs of defined benefit plans represent the portion of unrecognized transition obligation, prior service cost and net actuarial losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured. Of the regulatory asset and liability balances recorded, the following costs of $44 million for PPL, $13 million for PPL Electric, $31 million for LKE, $21 million for LG&E and $10 millionfor KU are expected to be amortized into net periodic defined benefit costs in 2012. All costs will be amortized over the average service lives of plan participants.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes. Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenses in a base rate case.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2029 for PPL Electric. Such costs are being amortized through 2035for LG&E and 2036 for PPL, LKE and KU.

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 and will be amortized over the life of the replacement debt.

Accumulated Cost of Removal

LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. See Note 1 for additional information.

PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the deferral of costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.

(PPL, LKE, LG&E and KU)

ECR

Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is recovered within 12 months. LG&E and KU are authorized to receive a 10.63% return on equity for the 2005, 2006 and 2009 compliance plans and a 10.10% return on projects associated with the 2011 compliance plan.

Coal Contracts

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current marketprices and offsets to regulatory liabilitiesfor those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjustedquarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indicesbetween the shareholders and the customers during each performance-based rate year (12 months ending October 31).The regulatory assets or liabilitiesrepresent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.

Fuel Adjustments

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs,from the costs embedded in base ratesare adjusted in LG&E's and KU's rates. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and,to the extent appropriate, reestablish the fuel charge included in base rates.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are recovered within 12 months.

Interest Rate Swaps

(PPL, LKE and LG&E)

Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an Order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures through 2033. Amortization of the gain/loss related to the terminated swap contract is recovered through 2035 as approved by the KPSC.

(LKE and LG&E)

In the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflect the reclassification of its ineffective swaps and terminated swap to regulatory assets based on an Order from the KPSC in the 2010 rate case whereby the cost of LG&E's terminated swap was allowed to be recovered in base rates. Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within other comprehensive income and common equity. The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.

(PPL, LKE, LG&E and KU)

AROs

As noted in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&Eand ARO liability.

DSM

DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM rate mechanism that provides for concurrent recovery of DSM costs and also provides an incentive for implementing DSM programs. The provision also allows LG&E and KU to recover revenues from lost sales associated with the DSM programs up to the earlier of three years or implementation of new base rates which reflect that load reduction.In addition, with the KPSC Order issued in November 2011, the DSM mechanism now includes a provision to earn a return of and on capital investment for DSM programs. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanism.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's fair values of the OVEC power purchase agreement were recorded on the balance sheets with offsetsto regulatory liabilities. Theregulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition, and have no impact on rate making.

Regulatory Liability associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized. For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.

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 the CSAPR, National Ambient Air Quality Standards andMATS, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants 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 plant as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at the Mill Creek generating plant and on Unit 1 at the Trimble County generating plant. KU requested $1.1 billion to upgrade fabric-filter baghouse systems for increased particulate and mercury control on all units at the E.W. Brown and Ghent generating plants and to convert a wet storage facility to a dry landfill at the E.W. Brown generating plant.

InNovember 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans.  The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings.  The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction.  The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings.  See Note 15 for additional information.

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 concluded during the fourth quarter. 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. LG&E and KU are awaiting the KPSC Staff report, which will close this proceeding.

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 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 plant and also onecoal-fired generating unit at KU's Tyrone plantand two at KU's Green Riverplant. 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. Formal requests for recovery of the costs associated with the NGCC construction and theacquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

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.

In connection with the 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 is in excess of 10.75%, fifty percent of the excess amount will be deferred as a regulatory liability and ultimately returned to customers.  The first ASSD filing will be made by April 1, 2012 based on the 2011 calendar year. Based upon 2011 earnings and their 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 as of December 31, 2011. 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.

Independent Transmission Operators

LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approvalto transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is required, and an application requesting approval was filed in January 2012.

Storm Costs

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 2011requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.

In September 2009, the KPSC approved the deferral of $44 million and $57 million for LG&E and KUof costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million and $2 million for LG&E and KU of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assetsover a ten-year amortization period ending July 2020.

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 concluded in September 2011. In November 2011, the KPSC approved the application as filed. The new rates were effective December 30, 2011.

Virginia Activities(PPL, LKE and KU)

IRP

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 provides historical and projected demand, resource and financial data, and other operating performance and system information and 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.

Virginia 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 amortization 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, and KU began recovering these costs over a five-year amortization period ending October 2016.

Pennsylvania Activities(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. EDCs not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). 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 (up to a maximum of $250 million) by PPL Electric to implement the plan. Such costs include direct and indirect charges, including design, general and administrative costs and applicable state evaluator costs, and are being recovered over the period from January 1, 2010 through May 31, 2013. The costs are recovered through the Act 129 Compliance Rider from all customers who receive distribution service. The program contains a reconciliation mechanism whereby any over- or under-recovery from customers will be refunded or collected at the end of the program. 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. PPL Electric filed its Program Year 2 Annual Report and Process Evaluation Report in November 2011. In February 2012, PPL Electric filed a petition with the PUC requesting permission to implement additional changes to its EE&C Plan. Other parties have 30 days to file comments to this petition; PPL Electric has 20 days to file reply comments.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

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 continues to procure power for its PLR obligations under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

Smart Meter Rider

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs 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. 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 its Section 1307(e)cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments. The SMR,which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year. 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 its planned actions for 2012. PPL Electric also submitted revisedSMR charges which became effective January 1, 2012.

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 current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focused 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 to 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 filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. 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. Parties filed comments to that tentative order. 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. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future 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. In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvements charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 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 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.

In 2007, based on PUC approval, a regulatory asset of $12 million was established for actual costs incurred associated with severe ice storms that occurred in January 2005. Recovery began in January 2008 and will continue through August 2015.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism. The tariff allows for recovery of actual transmission costs incurred, a return on transmission plant placed in service and an incentive return, including a return on construction work in progress, on the Susquehanna-Roseland transmission line project. The tariff utilizes actual costs from the most recent FERC Form No. 1 to set the rate for the current year billing to customers, including a true-up to adjust for actual costs in the subsequent year's FERC Form No. 1. The annual update of the rate is implemented automatically without requiring specific approval by the FERC before going into effect. PPL Electric accrues or defers revenues applicable to any estimated true-up of this formula-based rate.

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 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 the 2011 Annual Update of its formula rate. In October 2011, the group of municipal customers filed a preliminary challenge to the update.PPL Electric was not able to resolve the issues that were raised in this preliminary challenge and the group of municipal customers filed a formal challenge.PPL Electric filed a response to that formal challenge and the group of municipal customers filed an answer to that response.PPL Electric cannot predict the outcome of these two proceedings, which remain pending before the FERC.

In March 2012, PPL Electric plans to file 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 sheet. 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.

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 $120 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) should comply 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 $198 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 2011, WPD Midlands recorded a liability of $68 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. The balance at December 31, 2011 was $57 million.

Ofgem Review of Line Loss Calculation

WPD has a $170 million liabilityrecorded at December 31, 2011, calculated in accordance with an 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; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.

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.

LKE [Member]

Public Utilities Disclosure [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.

(PPL, LKE, LG&E and KU)

LG&E issubject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECRmechanism. As such, regulatory assets generally earn a return.

As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at the acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect the original contracted prices for these contracts.

(PPL, LKE and KU)

KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.

KU's rates tomunicipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.

(PPL and PPL Electric)

PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(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
		2011		2010		2011		2010
Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider				10				10
	Gas supply clause	$	6		4
	Fuel adjustment clause		3		3
	Other				23				8
Total current regulatory assets		$	9	$	85			$	63
Noncurrent Regulatory Assets:
	Defined benefit plans	$	615	$	592	$	276	$	262
	Taxes recoverable through future rates		289		254		289		254
	Storm costs		154		129		31		7
	Unamortized loss on debt		110		61		77		27
	Interest rate swaps		69		43
	Accumulated cost of removal of utility plant (b)		53		35		53		35
	Coal contracts (c)		11		22
	AROs		18		9
	Other		30		35		3		7
Total noncurrent regulatory assets		$	1,349	$	1,180	$	729	$	592

Current Regulatory Liabilities:
	Coal contracts (c)			$	46
	Generation supply charge (a)	$	42			$	42
	ECR		7		12
	PURTA tax				10			$	10
	Gas supply clause		6		9
	Transmission service charge		2		8		2		8
	Other		16		24		9
Total current regulatory liabilities		$	73	$	109	$	53	$	18
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	651	$	623
	Coal contracts (c)		180		213
	Power purchase agreement - OVEC (c)		116		124
	Net deferred tax assets		39		40
	Act 129 compliance rider		7		14	$	7	$	14
	Defined benefit plans		9		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,010	$	1,031	$	7	$	14

		LKE				LG&E				KU
		2011		2010		2011		2010		2011		2010
Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)				5				1			$	4
	Gas supply clause	$	6		4	$	6		4
	Fuel adjustment clause		3		3		3		3
	Virginia fuel factor				5								5
Total current regulatory assets		$	9	$	22	$	9	$	13			$	9
Noncurrent Regulatory Assets:
	Defined benefit plans	$	339	$	330	$	225	$	213	$	114	$	117
	Storm costs		123		122		66		65		57		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		69		43		69		43
	Coal contracts (c)		11		22		5		8		6		14
	AROs		18		9		11		7		7		2
	Other		27		28		6		9		21		19
Total noncurrent regulatory assets		$	620	$	588	$	403	$	367	$	217	$	221

Current Regulatory Liabilities:
		Coal contracts (c)			$	46			$	31			$	15
		ECR	$	7		12					$	7		12
		Gas supply clause		6		9	$	6		9
		Other		7		24		4		11		3		13
Total current regulatory liabilities			$	20	$	91	$	10	$	51	$	10	$	40
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	651	$	623	$	286	$	275	$	365	$	348
	Coal contracts (c)			180		213		78		87		102		126
	Power purchase agreement - OVEC (c)			116		124		80		86		36		38
	Net deferred tax assets			39		40		31		34		8		6
	Defined benefit plans			9		10						9		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,003	$	1,017	$	478	$	483	$	525	$	534

(a)       PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at December 31, 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 Assets and Liabilities

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

(PPL and PPL Electric)

Generation Supply Charge

The generation supply charge is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLRcustomers who receive basic generation supply service.The recovery includes charges for generation supply (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.

Universal Service Rider (USR)

PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers. Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP). OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills. This program is funded by residential customers and administered by community-based organizations. Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services. The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services. The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules. The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

PURTA Tax

In December 2009, PPL Electric reached a settlement with the Pennsylvania Department of Revenue related to the appeal of its 1997 PURTA tax assessments that resulted in a reduction in PURTA tax. Substantially all of the regulatory liability was refunded to customers in 2011 pursuant to PUC regulations.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric filed its energy efficiency and conservation plan in July 2009. The plan was approved by PUC Order in October 2009. The Order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May31, 2013. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or collected at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLRcustomers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

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

Defined Benefit Plans

Recoverable costs of defined benefit plans represent the portion of unrecognized transition obligation, prior service cost and net actuarial losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured. Of the regulatory asset and liability balances recorded, the following costs of $44 million for PPL, $13 million for PPL Electric, $31 million for LKE, $21 million for LG&E and $10 millionfor KU are expected to be amortized into net periodic defined benefit costs in 2012. All costs will be amortized over the average service lives of plan participants.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes. Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenses in a base rate case.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2029 for PPL Electric. Such costs are being amortized through 2035for LG&E and 2036 for PPL, LKE and KU.

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 and will be amortized over the life of the replacement debt.

Accumulated Cost of Removal

LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. See Note 1 for additional information.

PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the deferral of costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.

(PPL, LKE, LG&E and KU)

ECR

Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is recovered within 12 months. LG&E and KU are authorized to receive a 10.63% return on equity for the 2005, 2006 and 2009 compliance plans and a 10.10% return on projects associated with the 2011 compliance plan.

Coal Contracts

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current marketprices and offsets to regulatory liabilitiesfor those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjustedquarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indicesbetween the shareholders and the customers during each performance-based rate year (12 months ending October 31).The regulatory assets or liabilitiesrepresent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.

Fuel Adjustments

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs,from the costs embedded in base ratesare adjusted in LG&E's and KU's rates. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and,to the extent appropriate, reestablish the fuel charge included in base rates.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are recovered within 12 months.

Interest Rate Swaps

(PPL, LKE and LG&E)

Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an Order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures through 2033. Amortization of the gain/loss related to the terminated swap contract is recovered through 2035 as approved by the KPSC.

(LKE and LG&E)

In the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflect the reclassification of its ineffective swaps and terminated swap to regulatory assets based on an Order from the KPSC in the 2010 rate case whereby the cost of LG&E's terminated swap was allowed to be recovered in base rates. Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within other comprehensive income and common equity. The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.

(PPL, LKE, LG&E and KU)

AROs

As noted in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&Eand ARO liability.

DSM

DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM rate mechanism that provides for concurrent recovery of DSM costs and also provides an incentive for implementing DSM programs. The provision also allows LG&E and KU to recover revenues from lost sales associated with the DSM programs up to the earlier of three years or implementation of new base rates which reflect that load reduction.In addition, with the KPSC Order issued in November 2011, the DSM mechanism now includes a provision to earn a return of and on capital investment for DSM programs. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanism.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's fair values of the OVEC power purchase agreement were recorded on the balance sheets with offsetsto regulatory liabilities. Theregulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition, and have no impact on rate making.

Regulatory Liability associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized. For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.

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 the CSAPR, National Ambient Air Quality Standards andMATS, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants 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 plant as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at the Mill Creek generating plant and on Unit 1 at the Trimble County generating plant. KU requested $1.1 billion to upgrade fabric-filter baghouse systems for increased particulate and mercury control on all units at the E.W. Brown and Ghent generating plants and to convert a wet storage facility to a dry landfill at the E.W. Brown generating plant.

InNovember 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans.  The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings.  The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction.  The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings.  See Note 15 for additional information.

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 concluded during the fourth quarter. 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. LG&E and KU are awaiting the KPSC Staff report, which will close this proceeding.

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 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 plant and also onecoal-fired generating unit at KU's Tyrone plantand two at KU's Green Riverplant. 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. Formal requests for recovery of the costs associated with the NGCC construction and theacquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

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.

In connection with the 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 is in excess of 10.75%, fifty percent of the excess amount will be deferred as a regulatory liability and ultimately returned to customers.  The first ASSD filing will be made by April 1, 2012 based on the 2011 calendar year. Based upon 2011 earnings and their 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 as of December 31, 2011. 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.

Independent Transmission Operators

LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approvalto transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is required, and an application requesting approval was filed in January 2012.

Storm Costs

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 2011requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.

In September 2009, the KPSC approved the deferral of $44 million and $57 million for LG&E and KUof costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million and $2 million for LG&E and KU of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assetsover a ten-year amortization period ending July 2020.

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 concluded in September 2011. In November 2011, the KPSC approved the application as filed. The new rates were effective December 30, 2011.

Virginia Activities(PPL, LKE and KU)

IRP

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 provides historical and projected demand, resource and financial data, and other operating performance and system information and 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.

Virginia 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 amortization 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, and KU began recovering these costs over a five-year amortization period ending October 2016.

Pennsylvania Activities(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. EDCs not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). 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 (up to a maximum of $250 million) by PPL Electric to implement the plan. Such costs include direct and indirect charges, including design, general and administrative costs and applicable state evaluator costs, and are being recovered over the period from January 1, 2010 through May 31, 2013. The costs are recovered through the Act 129 Compliance Rider from all customers who receive distribution service. The program contains a reconciliation mechanism whereby any over- or under-recovery from customers will be refunded or collected at the end of the program. 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. PPL Electric filed its Program Year 2 Annual Report and Process Evaluation Report in November 2011. In February 2012, PPL Electric filed a petition with the PUC requesting permission to implement additional changes to its EE&C Plan. Other parties have 30 days to file comments to this petition; PPL Electric has 20 days to file reply comments.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

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 continues to procure power for its PLR obligations under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

Smart Meter Rider

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs 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. 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 its Section 1307(e)cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments. The SMR,which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year. 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 its planned actions for 2012. PPL Electric also submitted revisedSMR charges which became effective January 1, 2012.

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 current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focused 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 to 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 filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. 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. Parties filed comments to that tentative order. 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. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future 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. In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvements charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 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 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.

In 2007, based on PUC approval, a regulatory asset of $12 million was established for actual costs incurred associated with severe ice storms that occurred in January 2005. Recovery began in January 2008 and will continue through August 2015.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism. The tariff allows for recovery of actual transmission costs incurred, a return on transmission plant placed in service and an incentive return, including a return on construction work in progress, on the Susquehanna-Roseland transmission line project. The tariff utilizes actual costs from the most recent FERC Form No. 1 to set the rate for the current year billing to customers, including a true-up to adjust for actual costs in the subsequent year's FERC Form No. 1. The annual update of the rate is implemented automatically without requiring specific approval by the FERC before going into effect. PPL Electric accrues or defers revenues applicable to any estimated true-up of this formula-based rate.

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 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 the 2011 Annual Update of its formula rate. In October 2011, the group of municipal customers filed a preliminary challenge to the update.PPL Electric was not able to resolve the issues that were raised in this preliminary challenge and the group of municipal customers filed a formal challenge.PPL Electric filed a response to that formal challenge and the group of municipal customers filed an answer to that response.PPL Electric cannot predict the outcome of these two proceedings, which remain pending before the FERC.

In March 2012, PPL Electric plans to file 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 sheet. 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.

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 $120 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) should comply 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 $198 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 2011, WPD Midlands recorded a liability of $68 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. The balance at December 31, 2011 was $57 million.

Ofgem Review of Line Loss Calculation

WPD has a $170 million liabilityrecorded at December 31, 2011, calculated in accordance with an 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; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.

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.

LGE [Member]

Public Utilities Disclosure [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.

(PPL, LKE, LG&E and KU)

LG&E issubject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECRmechanism. As such, regulatory assets generally earn a return.

As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at the acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect the original contracted prices for these contracts.

(PPL, LKE and KU)

KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.

KU's rates tomunicipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.

(PPL and PPL Electric)

PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(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
		2011		2010		2011		2010
Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider				10				10
	Gas supply clause	$	6		4
	Fuel adjustment clause		3		3
	Other				23				8
Total current regulatory assets		$	9	$	85			$	63
Noncurrent Regulatory Assets:
	Defined benefit plans	$	615	$	592	$	276	$	262
	Taxes recoverable through future rates		289		254		289		254
	Storm costs		154		129		31		7
	Unamortized loss on debt		110		61		77		27
	Interest rate swaps		69		43
	Accumulated cost of removal of utility plant (b)		53		35		53		35
	Coal contracts (c)		11		22
	AROs		18		9
	Other		30		35		3		7
Total noncurrent regulatory assets		$	1,349	$	1,180	$	729	$	592

Current Regulatory Liabilities:
	Coal contracts (c)			$	46
	Generation supply charge (a)	$	42			$	42
	ECR		7		12
	PURTA tax				10			$	10
	Gas supply clause		6		9
	Transmission service charge		2		8		2		8
	Other		16		24		9
Total current regulatory liabilities		$	73	$	109	$	53	$	18
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	651	$	623
	Coal contracts (c)		180		213
	Power purchase agreement - OVEC (c)		116		124
	Net deferred tax assets		39		40
	Act 129 compliance rider		7		14	$	7	$	14
	Defined benefit plans		9		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,010	$	1,031	$	7	$	14

		LKE				LG&E				KU
		2011		2010		2011		2010		2011		2010
Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)				5				1			$	4
	Gas supply clause	$	6		4	$	6		4
	Fuel adjustment clause		3		3		3		3
	Virginia fuel factor				5								5
Total current regulatory assets		$	9	$	22	$	9	$	13			$	9
Noncurrent Regulatory Assets:
	Defined benefit plans	$	339	$	330	$	225	$	213	$	114	$	117
	Storm costs		123		122		66		65		57		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		69		43		69		43
	Coal contracts (c)		11		22		5		8		6		14
	AROs		18		9		11		7		7		2
	Other		27		28		6		9		21		19
Total noncurrent regulatory assets		$	620	$	588	$	403	$	367	$	217	$	221

Current Regulatory Liabilities:
		Coal contracts (c)			$	46			$	31			$	15
		ECR	$	7		12					$	7		12
		Gas supply clause		6		9	$	6		9
		Other		7		24		4		11		3		13
Total current regulatory liabilities			$	20	$	91	$	10	$	51	$	10	$	40
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	651	$	623	$	286	$	275	$	365	$	348
	Coal contracts (c)			180		213		78		87		102		126
	Power purchase agreement - OVEC (c)			116		124		80		86		36		38
	Net deferred tax assets			39		40		31		34		8		6
	Defined benefit plans			9		10						9		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,003	$	1,017	$	478	$	483	$	525	$	534

(a)       PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at December 31, 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 Assets and Liabilities

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

(PPL and PPL Electric)

Generation Supply Charge

The generation supply charge is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLRcustomers who receive basic generation supply service.The recovery includes charges for generation supply (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.

Universal Service Rider (USR)

PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers. Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP). OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills. This program is funded by residential customers and administered by community-based organizations. Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services. The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services. The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules. The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

PURTA Tax

In December 2009, PPL Electric reached a settlement with the Pennsylvania Department of Revenue related to the appeal of its 1997 PURTA tax assessments that resulted in a reduction in PURTA tax. Substantially all of the regulatory liability was refunded to customers in 2011 pursuant to PUC regulations.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric filed its energy efficiency and conservation plan in July 2009. The plan was approved by PUC Order in October 2009. The Order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May31, 2013. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or collected at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLRcustomers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

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

Defined Benefit Plans

Recoverable costs of defined benefit plans represent the portion of unrecognized transition obligation, prior service cost and net actuarial losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured. Of the regulatory asset and liability balances recorded, the following costs of $44 million for PPL, $13 million for PPL Electric, $31 million for LKE, $21 million for LG&E and $10 millionfor KU are expected to be amortized into net periodic defined benefit costs in 2012. All costs will be amortized over the average service lives of plan participants.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes. Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenses in a base rate case.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2029 for PPL Electric. Such costs are being amortized through 2035for LG&E and 2036 for PPL, LKE and KU.

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 and will be amortized over the life of the replacement debt.

Accumulated Cost of Removal

LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. See Note 1 for additional information.

PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the deferral of costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.

(PPL, LKE, LG&E and KU)

ECR

Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is recovered within 12 months. LG&E and KU are authorized to receive a 10.63% return on equity for the 2005, 2006 and 2009 compliance plans and a 10.10% return on projects associated with the 2011 compliance plan.

Coal Contracts

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current marketprices and offsets to regulatory liabilitiesfor those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjustedquarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indicesbetween the shareholders and the customers during each performance-based rate year (12 months ending October 31).The regulatory assets or liabilitiesrepresent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.

Fuel Adjustments

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs,from the costs embedded in base ratesare adjusted in LG&E's and KU's rates. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and,to the extent appropriate, reestablish the fuel charge included in base rates.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are recovered within 12 months.

Interest Rate Swaps

(PPL, LKE and LG&E)

Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an Order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures through 2033. Amortization of the gain/loss related to the terminated swap contract is recovered through 2035 as approved by the KPSC.

(LKE and LG&E)

In the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflect the reclassification of its ineffective swaps and terminated swap to regulatory assets based on an Order from the KPSC in the 2010 rate case whereby the cost of LG&E's terminated swap was allowed to be recovered in base rates. Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within other comprehensive income and common equity. The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.

(PPL, LKE, LG&E and KU)

AROs

As noted in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&Eand ARO liability.

DSM

DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM rate mechanism that provides for concurrent recovery of DSM costs and also provides an incentive for implementing DSM programs. The provision also allows LG&E and KU to recover revenues from lost sales associated with the DSM programs up to the earlier of three years or implementation of new base rates which reflect that load reduction.In addition, with the KPSC Order issued in November 2011, the DSM mechanism now includes a provision to earn a return of and on capital investment for DSM programs. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanism.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's fair values of the OVEC power purchase agreement were recorded on the balance sheets with offsetsto regulatory liabilities. Theregulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition, and have no impact on rate making.

Regulatory Liability associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized. For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.

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 the CSAPR, National Ambient Air Quality Standards andMATS, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants 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 plant as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at the Mill Creek generating plant and on Unit 1 at the Trimble County generating plant. KU requested $1.1 billion to upgrade fabric-filter baghouse systems for increased particulate and mercury control on all units at the E.W. Brown and Ghent generating plants and to convert a wet storage facility to a dry landfill at the E.W. Brown generating plant.

InNovember 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans.  The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings.  The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction.  The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings.  See Note 15 for additional information.

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 concluded during the fourth quarter. 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. LG&E and KU are awaiting the KPSC Staff report, which will close this proceeding.

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 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 plant and also onecoal-fired generating unit at KU's Tyrone plantand two at KU's Green Riverplant. 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. Formal requests for recovery of the costs associated with the NGCC construction and theacquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

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.

In connection with the 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 is in excess of 10.75%, fifty percent of the excess amount will be deferred as a regulatory liability and ultimately returned to customers.  The first ASSD filing will be made by April 1, 2012 based on the 2011 calendar year. Based upon 2011 earnings and their 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 as of December 31, 2011. 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.

Independent Transmission Operators

LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approvalto transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is required, and an application requesting approval was filed in January 2012.

Storm Costs

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 2011requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.

In September 2009, the KPSC approved the deferral of $44 million and $57 million for LG&E and KUof costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million and $2 million for LG&E and KU of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assetsover a ten-year amortization period ending July 2020.

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 concluded in September 2011. In November 2011, the KPSC approved the application as filed. The new rates were effective December 30, 2011.

Virginia Activities(PPL, LKE and KU)

IRP

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 provides historical and projected demand, resource and financial data, and other operating performance and system information and 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.

Virginia 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 amortization 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, and KU began recovering these costs over a five-year amortization period ending October 2016.

Pennsylvania Activities(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. EDCs not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). 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 (up to a maximum of $250 million) by PPL Electric to implement the plan. Such costs include direct and indirect charges, including design, general and administrative costs and applicable state evaluator costs, and are being recovered over the period from January 1, 2010 through May 31, 2013. The costs are recovered through the Act 129 Compliance Rider from all customers who receive distribution service. The program contains a reconciliation mechanism whereby any over- or under-recovery from customers will be refunded or collected at the end of the program. 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. PPL Electric filed its Program Year 2 Annual Report and Process Evaluation Report in November 2011. In February 2012, PPL Electric filed a petition with the PUC requesting permission to implement additional changes to its EE&C Plan. Other parties have 30 days to file comments to this petition; PPL Electric has 20 days to file reply comments.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

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 continues to procure power for its PLR obligations under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

Smart Meter Rider

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs 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. 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 its Section 1307(e)cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments. The SMR,which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year. 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 its planned actions for 2012. PPL Electric also submitted revisedSMR charges which became effective January 1, 2012.

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 current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focused 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 to 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 filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. 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. Parties filed comments to that tentative order. 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. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future 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. In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvements charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 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 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.

In 2007, based on PUC approval, a regulatory asset of $12 million was established for actual costs incurred associated with severe ice storms that occurred in January 2005. Recovery began in January 2008 and will continue through August 2015.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism. The tariff allows for recovery of actual transmission costs incurred, a return on transmission plant placed in service and an incentive return, including a return on construction work in progress, on the Susquehanna-Roseland transmission line project. The tariff utilizes actual costs from the most recent FERC Form No. 1 to set the rate for the current year billing to customers, including a true-up to adjust for actual costs in the subsequent year's FERC Form No. 1. The annual update of the rate is implemented automatically without requiring specific approval by the FERC before going into effect. PPL Electric accrues or defers revenues applicable to any estimated true-up of this formula-based rate.

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 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 the 2011 Annual Update of its formula rate. In October 2011, the group of municipal customers filed a preliminary challenge to the update.PPL Electric was not able to resolve the issues that were raised in this preliminary challenge and the group of municipal customers filed a formal challenge.PPL Electric filed a response to that formal challenge and the group of municipal customers filed an answer to that response.PPL Electric cannot predict the outcome of these two proceedings, which remain pending before the FERC.

In March 2012, PPL Electric plans to file 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 sheet. 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.

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 $120 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) should comply 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 $198 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 2011, WPD Midlands recorded a liability of $68 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. The balance at December 31, 2011 was $57 million.

Ofgem Review of Line Loss Calculation

WPD has a $170 million liabilityrecorded at December 31, 2011, calculated in accordance with an 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; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.

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.

KU [Member]

Public Utilities Disclosure [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.

(PPL, LKE, LG&E and KU)

LG&E issubject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECRmechanism. As such, regulatory assets generally earn a return.

As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at the acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect the original contracted prices for these contracts.

(PPL, LKE and KU)

KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.

KU's rates tomunicipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.

(PPL and PPL Electric)

PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(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
		2011		2010		2011		2010
Current Regulatory Assets:
	Generation supply charge (a)			$	45			$	45
	Universal service rider				10				10
	Gas supply clause	$	6		4
	Fuel adjustment clause		3		3
	Other				23				8
Total current regulatory assets		$	9	$	85			$	63
Noncurrent Regulatory Assets:
	Defined benefit plans	$	615	$	592	$	276	$	262
	Taxes recoverable through future rates		289		254		289		254
	Storm costs		154		129		31		7
	Unamortized loss on debt		110		61		77		27
	Interest rate swaps		69		43
	Accumulated cost of removal of utility plant (b)		53		35		53		35
	Coal contracts (c)		11		22
	AROs		18		9
	Other		30		35		3		7
Total noncurrent regulatory assets		$	1,349	$	1,180	$	729	$	592

Current Regulatory Liabilities:
	Coal contracts (c)			$	46
	Generation supply charge (a)	$	42			$	42
	ECR		7		12
	PURTA tax				10			$	10
	Gas supply clause		6		9
	Transmission service charge		2		8		2		8
	Other		16		24		9
Total current regulatory liabilities		$	73	$	109	$	53	$	18
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	651	$	623
	Coal contracts (c)		180		213
	Power purchase agreement - OVEC (c)		116		124
	Net deferred tax assets		39		40
	Act 129 compliance rider		7		14	$	7	$	14
	Defined benefit plans		9		10
	Other		8		7
Total noncurrent regulatory liabilities		$	1,010	$	1,031	$	7	$	14

		LKE				LG&E				KU
		2011		2010		2011		2010		2011		2010
Current Regulatory Assets:
	ECR			$	5			$	5
	Coal contracts (c)				5				1			$	4
	Gas supply clause	$	6		4	$	6		4
	Fuel adjustment clause		3		3		3		3
	Virginia fuel factor				5								5
Total current regulatory assets		$	9	$	22	$	9	$	13			$	9
Noncurrent Regulatory Assets:
	Defined benefit plans	$	339	$	330	$	225	$	213	$	114	$	117
	Storm costs		123		122		66		65		57		57
	Unamortized loss on debt		33		34		21		22		12		12
	Interest rate swaps		69		43		69		43
	Coal contracts (c)		11		22		5		8		6		14
	AROs		18		9		11		7		7		2
	Other		27		28		6		9		21		19
Total noncurrent regulatory assets		$	620	$	588	$	403	$	367	$	217	$	221

Current Regulatory Liabilities:
		Coal contracts (c)			$	46			$	31			$	15
		ECR	$	7		12					$	7		12
		Gas supply clause		6		9	$	6		9
		Other		7		24		4		11		3		13
Total current regulatory liabilities			$	20	$	91	$	10	$	51	$	10	$	40
Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	651	$	623	$	286	$	275	$	365	$	348
	Coal contracts (c)			180		213		78		87		102		126
	Power purchase agreement - OVEC (c)			116		124		80		86		36		38
	Net deferred tax assets			39		40		31		34		8		6
	Defined benefit plans			9		10						9		10
	Other			8		7		3		1		5		6
Total noncurrent regulatory liabilities			$	1,003	$	1,017	$	478	$	483	$	525	$	534

(a)       PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at December 31, 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 Assets and Liabilities

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

(PPL and PPL Electric)

Generation Supply Charge

The generation supply charge is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLRcustomers who receive basic generation supply service.The recovery includes charges for generation supply (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.

Universal Service Rider (USR)

PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers. Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP). OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills. This program is funded by residential customers and administered by community-based organizations. Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services. The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services. The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules. The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

PURTA Tax

In December 2009, PPL Electric reached a settlement with the Pennsylvania Department of Revenue related to the appeal of its 1997 PURTA tax assessments that resulted in a reduction in PURTA tax. Substantially all of the regulatory liability was refunded to customers in 2011 pursuant to PUC regulations.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric filed its energy efficiency and conservation plan in July 2009. The plan was approved by PUC Order in October 2009. The Order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May31, 2013. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or collected at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.

Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLRcustomers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

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

Defined Benefit Plans

Recoverable costs of defined benefit plans represent the portion of unrecognized transition obligation, prior service cost and net actuarial losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured. Of the regulatory asset and liability balances recorded, the following costs of $44 million for PPL, $13 million for PPL Electric, $31 million for LKE, $21 million for LG&E and $10 millionfor KU are expected to be amortized into net periodic defined benefit costs in 2012. All costs will be amortized over the average service lives of plan participants.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes. Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenses in a base rate case.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2029 for PPL Electric. Such costs are being amortized through 2035for LG&E and 2036 for PPL, LKE and KU.

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 and will be amortized over the life of the replacement debt.

Accumulated Cost of Removal

LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. See Note 1 for additional information.

PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the deferral of costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.

(PPL, LKE, LG&E and KU)

ECR

Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is recovered within 12 months. LG&E and KU are authorized to receive a 10.63% return on equity for the 2005, 2006 and 2009 compliance plans and a 10.10% return on projects associated with the 2011 compliance plan.

Coal Contracts

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current marketprices and offsets to regulatory liabilitiesfor those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjustedquarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indicesbetween the shareholders and the customers during each performance-based rate year (12 months ending October 31).The regulatory assets or liabilitiesrepresent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.

Fuel Adjustments

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs,from the costs embedded in base ratesare adjusted in LG&E's and KU's rates. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and,to the extent appropriate, reestablish the fuel charge included in base rates.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are recovered within 12 months.

Interest Rate Swaps

(PPL, LKE and LG&E)

Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an Order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures through 2033. Amortization of the gain/loss related to the terminated swap contract is recovered through 2035 as approved by the KPSC.

(LKE and LG&E)

In the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflect the reclassification of its ineffective swaps and terminated swap to regulatory assets based on an Order from the KPSC in the 2010 rate case whereby the cost of LG&E's terminated swap was allowed to be recovered in base rates. Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within other comprehensive income and common equity. The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.

(PPL, LKE, LG&E and KU)

AROs

As noted in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&Eand ARO liability.

DSM

DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM rate mechanism that provides for concurrent recovery of DSM costs and also provides an incentive for implementing DSM programs. The provision also allows LG&E and KU to recover revenues from lost sales associated with the DSM programs up to the earlier of three years or implementation of new base rates which reflect that load reduction.In addition, with the KPSC Order issued in November 2011, the DSM mechanism now includes a provision to earn a return of and on capital investment for DSM programs. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanism.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's fair values of the OVEC power purchase agreement were recorded on the balance sheets with offsetsto regulatory liabilities. Theregulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition, and have no impact on rate making.

Regulatory Liability associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized. For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.

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 the CSAPR, National Ambient Air Quality Standards andMATS, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants 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 plant as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at the Mill Creek generating plant and on Unit 1 at the Trimble County generating plant. KU requested $1.1 billion to upgrade fabric-filter baghouse systems for increased particulate and mercury control on all units at the E.W. Brown and Ghent generating plants and to convert a wet storage facility to a dry landfill at the E.W. Brown generating plant.

InNovember 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans.  The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings.  The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction.  The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings.  See Note 15 for additional information.

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 concluded during the fourth quarter. 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. LG&E and KU are awaiting the KPSC Staff report, which will close this proceeding.

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 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 plant and also onecoal-fired generating unit at KU's Tyrone plantand two at KU's Green Riverplant. 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. Formal requests for recovery of the costs associated with the NGCC construction and theacquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.

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.

In connection with the 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 is in excess of 10.75%, fifty percent of the excess amount will be deferred as a regulatory liability and ultimately returned to customers.  The first ASSD filing will be made by April 1, 2012 based on the 2011 calendar year. Based upon 2011 earnings and their 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 as of December 31, 2011. 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.

Independent Transmission Operators

LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approvalto transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is required, and an application requesting approval was filed in January 2012.

Storm Costs

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 2011requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.

In September 2009, the KPSC approved the deferral of $44 million and $57 million for LG&E and KUof costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million and $2 million for LG&E and KU of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assetsover a ten-year amortization period ending July 2020.

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 concluded in September 2011. In November 2011, the KPSC approved the application as filed. The new rates were effective December 30, 2011.

Virginia Activities(PPL, LKE and KU)

IRP

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 provides historical and projected demand, resource and financial data, and other operating performance and system information and 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.

Virginia 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 amortization 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, and KU began recovering these costs over a five-year amortization period ending October 2016.

Pennsylvania Activities(PPL and PPL Electric)

Act 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. EDCs not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). 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 (up to a maximum of $250 million) by PPL Electric to implement the plan. Such costs include direct and indirect charges, including design, general and administrative costs and applicable state evaluator costs, and are being recovered over the period from January 1, 2010 through May 31, 2013. The costs are recovered through the Act 129 Compliance Rider from all customers who receive distribution service. The program contains a reconciliation mechanism whereby any over- or under-recovery from customers will be refunded or collected at the end of the program. 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. PPL Electric filed its Program Year 2 Annual Report and Process Evaluation Report in November 2011. In February 2012, PPL Electric filed a petition with the PUC requesting permission to implement additional changes to its EE&C Plan. Other parties have 30 days to file comments to this petition; PPL Electric has 20 days to file reply comments.

Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.

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 continues to procure power for its PLR obligations under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.

Smart Meter Rider

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs 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. 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 its Section 1307(e)cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments. The SMR,which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year. 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 its planned actions for 2012. PPL Electric also submitted revisedSMR charges which became effective January 1, 2012.

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 current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focused 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 to 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 filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. 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. Parties filed comments to that tentative order. 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. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future 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. In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvements charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.

Storm Recovery

PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 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 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.

In 2007, based on PUC approval, a regulatory asset of $12 million was established for actual costs incurred associated with severe ice storms that occurred in January 2005. Recovery began in January 2008 and will continue through August 2015.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism. The tariff allows for recovery of actual transmission costs incurred, a return on transmission plant placed in service and an incentive return, including a return on construction work in progress, on the Susquehanna-Roseland transmission line project. The tariff utilizes actual costs from the most recent FERC Form No. 1 to set the rate for the current year billing to customers, including a true-up to adjust for actual costs in the subsequent year's FERC Form No. 1. The annual update of the rate is implemented automatically without requiring specific approval by the FERC before going into effect. PPL Electric accrues or defers revenues applicable to any estimated true-up of this formula-based rate.

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 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 the 2011 Annual Update of its formula rate. In October 2011, the group of municipal customers filed a preliminary challenge to the update.PPL Electric was not able to resolve the issues that were raised in this preliminary challenge and the group of municipal customers filed a formal challenge.PPL Electric filed a response to that formal challenge and the group of municipal customers filed an answer to that response.PPL Electric cannot predict the outcome of these two proceedings, which remain pending before the FERC.

In March 2012, PPL Electric plans to file 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 sheet. 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.

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 $120 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) should comply 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 $198 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 2011, WPD Midlands recorded a liability of $68 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. The balance at December 31, 2011 was $57 million.

Ofgem Review of Line Loss Calculation

WPD has a $170 million liabilityrecorded at December 31, 2011, calculated in accordance with an 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; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.

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.