6. Utility Rate Regulation

Regulatory Assets and Liabilities

(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 is subject 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 short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms. As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.

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 LKE's 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 to municipal 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
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	11	$	6
	Fuel adjustment clause		6		3
	Other		2
Total current regulatory assets		$	19	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	730	$	615	$	362	$	276
	Taxes recoverable through future rates		293		289		293		289
	Storm costs		168		154		59		31
	Unamortized loss on debt		96		110		65		77
	Interest rate swaps		67		69
	Accumulated cost of removal of utility plant		71		53		71		53
	Coal contracts (a)		4		11
	AROs		26		18
	Other		28		30		3		3
Total noncurrent regulatory assets		$	1,483	$	1,349	$	853	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	27	$	42	$	27	$	42
	ECR		4		7
	Gas supply clause		4		6
	Transmission service charge		6		2		6		2
	Transmission formula rate				5				5
	Universal Service Rider		17		1		17		1
	Other		3		10		2		3
Total current regulatory liabilities		$	61	$	73	$	52	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	679	$	651
	Coal contracts (a)		141		180
	Power purchase agreement - OVEC (a)		108		116
	Net deferred tax assets		34		39
	Act 129 compliance rider		8		7	$	8	$	7
	Defined benefit plans		17		9
	Interest rate swaps		14
	Other		9		8
Total noncurrent regulatory liabilities		$	1,010	$	1,010	$	8	$	7

		LKE				LG&E				KU
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	11	$	6	$	11	$	6
	Fuel adjustment clause		6		3		6		3
	Other		2				2
Total current regulatory assets		$	19	$	9	$	19	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	368	$	339	$	232	$	225	$	136	$	114
	Storm costs		109		123		59		66		50		57
	Unamortized loss on debt		31		33		20		21		11		12
	Interest rate swaps		67		69		67		69
	Coal contracts (a)		4		11		2		5		2		6
	AROs		26		18		15		11		11		7
	Other		25		27		5		6		20		21
Total noncurrent regulatory assets		$	630	$	620	$	400	$	403	$	230	$	217

Current Regulatory Liabilities:
		ECR	$	4	$	7					$	4	$	7
		Gas supply clause		4		6	$	4	$	6
		Other		1		7				4		1		3
Total current regulatory liabilities			$	9	$	20	$	4	$	10	$	5	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	679	$	651	$	297	$	286	$	382	$	365
	Coal contracts (a)			141		180		61		78		80		102
	Power purchase agreement - OVEC (a)			108		116		75		80		33		36
	Net deferred tax assets			34		39		28		31		6		8
	Defined benefit plans			17		9						17		9
	Interest rate swaps			14				7				7
	Other			9		8		3		3		6		5
Total noncurrent regulatory liabilities			$	1,002	$	1,003	$	471	$	478	$	531	$	525

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

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 PLR customers 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.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric's energy efficiency and conservation plan was approved by a 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 May 31, 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 recovered 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 PLR customers. 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.

Transmission Formula Rates

PPL Electric's transmission revenues are billed in accordance with a FERC-approved open access transmission tariff that utilizes a formula-based rate recovery mechanism. The formula rate is based on prior year expenditures and forecasted current calendar year transmission plant additions. An adjustment to the prior year expenditures is recorded as a regulatory asset or liability.

(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 and are amortized over the average service lives of plan participants. 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, costs of $60 million for PPL, $22 million for PPL Electric, $38 million for LKE, $24 million for LG&E and $14 million for KU are expected to be amortized into net periodic defined benefit costs in 2013.

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 2035 for LG&E and 2036 for PPL, LKE and KU.

Accumulated Cost of Removal of Utility Plant

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 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 typically recovered within 12 months. LG&E and KU are authorized to receive a 10.63% and 10.10% return on projects associated with the 2009 and 2011 compliance plans. As a result of the settlement agreement in the 2012 rate case, beginning in 2013, LG&E and KU will receive a 10.25% return on all ECR projects included in the 2009 and 2011 compliance plans.

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 market prices and offsets to regulatory liabilities for 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 adjusted quarterly 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 indices between the shareholders and the customers during each performance-based rate year (12 months ending October 31). The regulatory assets or liabilities represent 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 Adjustment Clauses

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 rates are 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 typically 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 OCI 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)

In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013. These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties. LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities. The gains and losses will be recognized in “Interest Expense” on the Statements of Income over the life of the underlying debt. See Note 19 for additional information related to the forward-starting interest rate swaps.

AROs

As discussed 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&E and ARO liability.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LKE, LG&E and KU with offsets to regulatory liabilities. The regulatory 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.

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)

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

Independent Transmission Operators

In September 2012, LG&E and KU completed the transition of their independent transmission operator contractual arrangements from Southwest Power Pool, Inc. to TranServ International, Inc. This change had previously received approvals of the FERC and the KPSC.

(PPL, LKE and LG&E)

CPCN Filing

In October 2012, LG&E filed an application with the KPSC to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station. The application partially modifies the existing authority granted by the KPSC in 2011, which authorized LG&E to build two new scrubbers to serve Mill Creek Units 1 and 2 and another to serve Mill Creek Unit 4. Additionally, authority was granted allowing the Mill Creek Unit 3 to be served by the existing Unit 4 scrubber. The CPCN sought approval to construct a new wet scrubber on Mill Creek Unit 3 instead of utilizing the Unit 4 scrubber. In February 2013, LG&E received the requested KPSC approval to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station.

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 2011, requesting 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 the request. On December 20, 2012, the KPSC in the approval of the unanimous rate case settlement agreement, authorized regulatory asset recovery effective January 1, 2013, over a five year period.

Pennsylvania Activities (PPL and PPL Electric)

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.

Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy. See “Storm Costs” below for additional information regarding Hurricane Sandy.

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 reduce overall electricity consumption by 1.0% by May 2011 and, by May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. EDCs will be able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan, and in March 2012 confirmed that PPL Electric met the 2011 requirement. PPL Electric will determine if it met the peak demand reduction target and the May 2013 energy reduction target after it completes the final program evaluation on November 5, 2013.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric filed its Phase II EE&C Plan with the PUC on November 15, 2012 and the PUC is expected to issue its decision in March 2013.

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

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.

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 was taking under its Smart Meter plan in 2011 and its planned actions for 2012. PPL Electric also submitted revised SMR charges which became effective January 1, 2012. In August 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter plan in 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC issued a tentative implementation order in early November 2012, following which parties had 30 days to provide comment. PPL Electric and PPL EnergyPlus filed joint comments. A final implementation order was issued on February 15, 2013. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.

Legislation - Regulatory Procedures and Mechanisms

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.

Storm Costs

During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in “Other operation and maintenance” on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in “Other operation and maintenance” on the Statement of Income. Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits. Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statement of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy. See “Rate Case Proceeding” above for information regarding PPL Electric's plan to file a proposed Storm Damage Expense Rider with the PUC.

PPL Electric experienced several PUC-reportable storms during 2011 including Hurricane Irene and a late October snow storm. Total restoration costs were $84 million, of which $54 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms 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 Statements 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 2011 snowstorm. PPL Electric recorded a regulatory asset of $25 million in December 2011 (offset to "Other operation and maintenance" on the Statement of Income). The PUC granted PPL Electric's recovery of the 2011 storm costs in its final order in the 2012 rate case. Recovery began in January 2013 and will continue over a five year period.

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.

PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update has been subsequently challenged by a group of municipal customers, which challenges have been opposed by PPL Electric. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its 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. At December 31, 2012 and 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013. In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology. This consultation also confirmed the final decisions will be published by April 2013. In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date. PPL cannot predict when this matter will be resolved.

Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.

European Market Infrastructure Regulation

Regulation No. 648/2012 of the European Parliament and of the Council, commonly referred to as the European Market Infrastructure Regulation (EMIR), entered into force on August 16, 2012 and the European Commission adopted most of the Regulatory Technical Standards without modification in December 2012. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

Regulatory Assets and Liabilities

(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 is subject 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 short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms. As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.

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 LKE's 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 to municipal 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
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	11	$	6
	Fuel adjustment clause		6		3
	Other		2
Total current regulatory assets		$	19	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	730	$	615	$	362	$	276
	Taxes recoverable through future rates		293		289		293		289
	Storm costs		168		154		59		31
	Unamortized loss on debt		96		110		65		77
	Interest rate swaps		67		69
	Accumulated cost of removal of utility plant		71		53		71		53
	Coal contracts (a)		4		11
	AROs		26		18
	Other		28		30		3		3
Total noncurrent regulatory assets		$	1,483	$	1,349	$	853	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	27	$	42	$	27	$	42
	ECR		4		7
	Gas supply clause		4		6
	Transmission service charge		6		2		6		2
	Transmission formula rate				5				5
	Universal Service Rider		17		1		17		1
	Other		3		10		2		3
Total current regulatory liabilities		$	61	$	73	$	52	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	679	$	651
	Coal contracts (a)		141		180
	Power purchase agreement - OVEC (a)		108		116
	Net deferred tax assets		34		39
	Act 129 compliance rider		8		7	$	8	$	7
	Defined benefit plans		17		9
	Interest rate swaps		14
	Other		9		8
Total noncurrent regulatory liabilities		$	1,010	$	1,010	$	8	$	7

		LKE				LG&E				KU
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	11	$	6	$	11	$	6
	Fuel adjustment clause		6		3		6		3
	Other		2				2
Total current regulatory assets		$	19	$	9	$	19	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	368	$	339	$	232	$	225	$	136	$	114
	Storm costs		109		123		59		66		50		57
	Unamortized loss on debt		31		33		20		21		11		12
	Interest rate swaps		67		69		67		69
	Coal contracts (a)		4		11		2		5		2		6
	AROs		26		18		15		11		11		7
	Other		25		27		5		6		20		21
Total noncurrent regulatory assets		$	630	$	620	$	400	$	403	$	230	$	217

Current Regulatory Liabilities:
		ECR	$	4	$	7					$	4	$	7
		Gas supply clause		4		6	$	4	$	6
		Other		1		7				4		1		3
Total current regulatory liabilities			$	9	$	20	$	4	$	10	$	5	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	679	$	651	$	297	$	286	$	382	$	365
	Coal contracts (a)			141		180		61		78		80		102
	Power purchase agreement - OVEC (a)			108		116		75		80		33		36
	Net deferred tax assets			34		39		28		31		6		8
	Defined benefit plans			17		9						17		9
	Interest rate swaps			14				7				7
	Other			9		8		3		3		6		5
Total noncurrent regulatory liabilities			$	1,002	$	1,003	$	471	$	478	$	531	$	525

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

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 PLR customers 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.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric's energy efficiency and conservation plan was approved by a 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 May 31, 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 recovered 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 PLR customers. 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.

Transmission Formula Rates

PPL Electric's transmission revenues are billed in accordance with a FERC-approved open access transmission tariff that utilizes a formula-based rate recovery mechanism. The formula rate is based on prior year expenditures and forecasted current calendar year transmission plant additions. An adjustment to the prior year expenditures is recorded as a regulatory asset or liability.

(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 and are amortized over the average service lives of plan participants. 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, costs of $60 million for PPL, $22 million for PPL Electric, $38 million for LKE, $24 million for LG&E and $14 million for KU are expected to be amortized into net periodic defined benefit costs in 2013.

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 2035 for LG&E and 2036 for PPL, LKE and KU.

Accumulated Cost of Removal of Utility Plant

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 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 typically recovered within 12 months. LG&E and KU are authorized to receive a 10.63% and 10.10% return on projects associated with the 2009 and 2011 compliance plans. As a result of the settlement agreement in the 2012 rate case, beginning in 2013, LG&E and KU will receive a 10.25% return on all ECR projects included in the 2009 and 2011 compliance plans.

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 market prices and offsets to regulatory liabilities for 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 adjusted quarterly 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 indices between the shareholders and the customers during each performance-based rate year (12 months ending October 31). The regulatory assets or liabilities represent 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 Adjustment Clauses

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 rates are 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 typically 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 OCI 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)

In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013. These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties. LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities. The gains and losses will be recognized in “Interest Expense” on the Statements of Income over the life of the underlying debt. See Note 19 for additional information related to the forward-starting interest rate swaps.

AROs

As discussed 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&E and ARO liability.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LKE, LG&E and KU with offsets to regulatory liabilities. The regulatory 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.

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)

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

Independent Transmission Operators

In September 2012, LG&E and KU completed the transition of their independent transmission operator contractual arrangements from Southwest Power Pool, Inc. to TranServ International, Inc. This change had previously received approvals of the FERC and the KPSC.

(PPL, LKE and LG&E)

CPCN Filing

In October 2012, LG&E filed an application with the KPSC to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station. The application partially modifies the existing authority granted by the KPSC in 2011, which authorized LG&E to build two new scrubbers to serve Mill Creek Units 1 and 2 and another to serve Mill Creek Unit 4. Additionally, authority was granted allowing the Mill Creek Unit 3 to be served by the existing Unit 4 scrubber. The CPCN sought approval to construct a new wet scrubber on Mill Creek Unit 3 instead of utilizing the Unit 4 scrubber. In February 2013, LG&E received the requested KPSC approval to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station.

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 2011, requesting 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 the request. On December 20, 2012, the KPSC in the approval of the unanimous rate case settlement agreement, authorized regulatory asset recovery effective January 1, 2013, over a five year period.

Pennsylvania Activities (PPL and PPL Electric)

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.

Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy. See “Storm Costs” below for additional information regarding Hurricane Sandy.

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 reduce overall electricity consumption by 1.0% by May 2011 and, by May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. EDCs will be able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan, and in March 2012 confirmed that PPL Electric met the 2011 requirement. PPL Electric will determine if it met the peak demand reduction target and the May 2013 energy reduction target after it completes the final program evaluation on November 5, 2013.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric filed its Phase II EE&C Plan with the PUC on November 15, 2012 and the PUC is expected to issue its decision in March 2013.

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

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.

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 was taking under its Smart Meter plan in 2011 and its planned actions for 2012. PPL Electric also submitted revised SMR charges which became effective January 1, 2012. In August 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter plan in 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC issued a tentative implementation order in early November 2012, following which parties had 30 days to provide comment. PPL Electric and PPL EnergyPlus filed joint comments. A final implementation order was issued on February 15, 2013. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.

Legislation - Regulatory Procedures and Mechanisms

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.

Storm Costs

During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in “Other operation and maintenance” on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in “Other operation and maintenance” on the Statement of Income. Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits. Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statement of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy. See “Rate Case Proceeding” above for information regarding PPL Electric's plan to file a proposed Storm Damage Expense Rider with the PUC.

PPL Electric experienced several PUC-reportable storms during 2011 including Hurricane Irene and a late October snow storm. Total restoration costs were $84 million, of which $54 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms 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 Statements 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 2011 snowstorm. PPL Electric recorded a regulatory asset of $25 million in December 2011 (offset to "Other operation and maintenance" on the Statement of Income). The PUC granted PPL Electric's recovery of the 2011 storm costs in its final order in the 2012 rate case. Recovery began in January 2013 and will continue over a five year period.

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.

PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update has been subsequently challenged by a group of municipal customers, which challenges have been opposed by PPL Electric. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its 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. At December 31, 2012 and 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013. In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology. This consultation also confirmed the final decisions will be published by April 2013. In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date. PPL cannot predict when this matter will be resolved.

Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.

European Market Infrastructure Regulation

Regulation No. 648/2012 of the European Parliament and of the Council, commonly referred to as the European Market Infrastructure Regulation (EMIR), entered into force on August 16, 2012 and the European Commission adopted most of the Regulatory Technical Standards without modification in December 2012. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

Regulatory Assets and Liabilities

(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 is subject 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 short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms. As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.

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 LKE's 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 to municipal 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
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	11	$	6
	Fuel adjustment clause		6		3
	Other		2
Total current regulatory assets		$	19	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	730	$	615	$	362	$	276
	Taxes recoverable through future rates		293		289		293		289
	Storm costs		168		154		59		31
	Unamortized loss on debt		96		110		65		77
	Interest rate swaps		67		69
	Accumulated cost of removal of utility plant		71		53		71		53
	Coal contracts (a)		4		11
	AROs		26		18
	Other		28		30		3		3
Total noncurrent regulatory assets		$	1,483	$	1,349	$	853	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	27	$	42	$	27	$	42
	ECR		4		7
	Gas supply clause		4		6
	Transmission service charge		6		2		6		2
	Transmission formula rate				5				5
	Universal Service Rider		17		1		17		1
	Other		3		10		2		3
Total current regulatory liabilities		$	61	$	73	$	52	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	679	$	651
	Coal contracts (a)		141		180
	Power purchase agreement - OVEC (a)		108		116
	Net deferred tax assets		34		39
	Act 129 compliance rider		8		7	$	8	$	7
	Defined benefit plans		17		9
	Interest rate swaps		14
	Other		9		8
Total noncurrent regulatory liabilities		$	1,010	$	1,010	$	8	$	7

		LKE				LG&E				KU
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	11	$	6	$	11	$	6
	Fuel adjustment clause		6		3		6		3
	Other		2				2
Total current regulatory assets		$	19	$	9	$	19	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	368	$	339	$	232	$	225	$	136	$	114
	Storm costs		109		123		59		66		50		57
	Unamortized loss on debt		31		33		20		21		11		12
	Interest rate swaps		67		69		67		69
	Coal contracts (a)		4		11		2		5		2		6
	AROs		26		18		15		11		11		7
	Other		25		27		5		6		20		21
Total noncurrent regulatory assets		$	630	$	620	$	400	$	403	$	230	$	217

Current Regulatory Liabilities:
		ECR	$	4	$	7					$	4	$	7
		Gas supply clause		4		6	$	4	$	6
		Other		1		7				4		1		3
Total current regulatory liabilities			$	9	$	20	$	4	$	10	$	5	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	679	$	651	$	297	$	286	$	382	$	365
	Coal contracts (a)			141		180		61		78		80		102
	Power purchase agreement - OVEC (a)			108		116		75		80		33		36
	Net deferred tax assets			34		39		28		31		6		8
	Defined benefit plans			17		9						17		9
	Interest rate swaps			14				7				7
	Other			9		8		3		3		6		5
Total noncurrent regulatory liabilities			$	1,002	$	1,003	$	471	$	478	$	531	$	525

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

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 PLR customers 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.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric's energy efficiency and conservation plan was approved by a 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 May 31, 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 recovered 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 PLR customers. 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.

Transmission Formula Rates

PPL Electric's transmission revenues are billed in accordance with a FERC-approved open access transmission tariff that utilizes a formula-based rate recovery mechanism. The formula rate is based on prior year expenditures and forecasted current calendar year transmission plant additions. An adjustment to the prior year expenditures is recorded as a regulatory asset or liability.

(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 and are amortized over the average service lives of plan participants. 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, costs of $60 million for PPL, $22 million for PPL Electric, $38 million for LKE, $24 million for LG&E and $14 million for KU are expected to be amortized into net periodic defined benefit costs in 2013.

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 2035 for LG&E and 2036 for PPL, LKE and KU.

Accumulated Cost of Removal of Utility Plant

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 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 typically recovered within 12 months. LG&E and KU are authorized to receive a 10.63% and 10.10% return on projects associated with the 2009 and 2011 compliance plans. As a result of the settlement agreement in the 2012 rate case, beginning in 2013, LG&E and KU will receive a 10.25% return on all ECR projects included in the 2009 and 2011 compliance plans.

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 market prices and offsets to regulatory liabilities for 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 adjusted quarterly 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 indices between the shareholders and the customers during each performance-based rate year (12 months ending October 31). The regulatory assets or liabilities represent 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 Adjustment Clauses

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 rates are 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 typically 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 OCI 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)

In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013. These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties. LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities. The gains and losses will be recognized in “Interest Expense” on the Statements of Income over the life of the underlying debt. See Note 19 for additional information related to the forward-starting interest rate swaps.

AROs

As discussed 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&E and ARO liability.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LKE, LG&E and KU with offsets to regulatory liabilities. The regulatory 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.

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)

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

Independent Transmission Operators

In September 2012, LG&E and KU completed the transition of their independent transmission operator contractual arrangements from Southwest Power Pool, Inc. to TranServ International, Inc. This change had previously received approvals of the FERC and the KPSC.

(PPL, LKE and LG&E)

CPCN Filing

In October 2012, LG&E filed an application with the KPSC to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station. The application partially modifies the existing authority granted by the KPSC in 2011, which authorized LG&E to build two new scrubbers to serve Mill Creek Units 1 and 2 and another to serve Mill Creek Unit 4. Additionally, authority was granted allowing the Mill Creek Unit 3 to be served by the existing Unit 4 scrubber. The CPCN sought approval to construct a new wet scrubber on Mill Creek Unit 3 instead of utilizing the Unit 4 scrubber. In February 2013, LG&E received the requested KPSC approval to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station.

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 2011, requesting 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 the request. On December 20, 2012, the KPSC in the approval of the unanimous rate case settlement agreement, authorized regulatory asset recovery effective January 1, 2013, over a five year period.

Pennsylvania Activities (PPL and PPL Electric)

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.

Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy. See “Storm Costs” below for additional information regarding Hurricane Sandy.

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 reduce overall electricity consumption by 1.0% by May 2011 and, by May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. EDCs will be able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan, and in March 2012 confirmed that PPL Electric met the 2011 requirement. PPL Electric will determine if it met the peak demand reduction target and the May 2013 energy reduction target after it completes the final program evaluation on November 5, 2013.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric filed its Phase II EE&C Plan with the PUC on November 15, 2012 and the PUC is expected to issue its decision in March 2013.

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

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.

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 was taking under its Smart Meter plan in 2011 and its planned actions for 2012. PPL Electric also submitted revised SMR charges which became effective January 1, 2012. In August 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter plan in 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC issued a tentative implementation order in early November 2012, following which parties had 30 days to provide comment. PPL Electric and PPL EnergyPlus filed joint comments. A final implementation order was issued on February 15, 2013. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.

Legislation - Regulatory Procedures and Mechanisms

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.

Storm Costs

During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in “Other operation and maintenance” on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in “Other operation and maintenance” on the Statement of Income. Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits. Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statement of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy. See “Rate Case Proceeding” above for information regarding PPL Electric's plan to file a proposed Storm Damage Expense Rider with the PUC.

PPL Electric experienced several PUC-reportable storms during 2011 including Hurricane Irene and a late October snow storm. Total restoration costs were $84 million, of which $54 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms 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 Statements 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 2011 snowstorm. PPL Electric recorded a regulatory asset of $25 million in December 2011 (offset to "Other operation and maintenance" on the Statement of Income). The PUC granted PPL Electric's recovery of the 2011 storm costs in its final order in the 2012 rate case. Recovery began in January 2013 and will continue over a five year period.

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.

PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update has been subsequently challenged by a group of municipal customers, which challenges have been opposed by PPL Electric. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its 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. At December 31, 2012 and 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013. In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology. This consultation also confirmed the final decisions will be published by April 2013. In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date. PPL cannot predict when this matter will be resolved.

Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.

European Market Infrastructure Regulation

Regulation No. 648/2012 of the European Parliament and of the Council, commonly referred to as the European Market Infrastructure Regulation (EMIR), entered into force on August 16, 2012 and the European Commission adopted most of the Regulatory Technical Standards without modification in December 2012. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.