6. Utility Rate Regulation

Regulatory Assets and Liabilities

(All Registrants except PPL Energy Supply)

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.

WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities. See Note 1 for additional information.

(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 adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets.

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.

(All Registrants except PPL Energy Supply)

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

		PPL				PPL Electric
		2013		2012		2013		2012

Current Regulatory Assets:
	Environmental cost recovery	$	7	$	1
	Gas supply clause		10		11
	Fuel adjustment clause		2		6
	Demand side management		8		1
	Other		6			$	6
Total current regulatory assets		$	33	$	19	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	509	$	730	$	257	$	362
	Taxes recoverable through future rates		306		293		306		293
	Storm costs		147		168		53		59
	Unamortized loss on debt		85		96		57		65
	Interest rate swaps		44		67
	Accumulated cost of removal of utility plant		98		71		98		71
	AROs		44		26
	Other		13		32		1		3
Total noncurrent regulatory assets		$	1,246	$	1,483	$	772	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	23	$	27	$	23	$	27
	Environmental cost recovery				4
	Gas supply clause		3		4
	Transmission service charge		8		6		8		6
	Transmission formula rate		20				20
	Fuel adjustment clause		4		1
	Universal Service Rider		10		17		10		17
	Storm damage expense		14				14
	Gas line tracker		6
	Other		2		2		1		2
Total current regulatory liabilities		$	90	$	61	$	76	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	688	$	679
	Coal contracts (a)		98		141
	Power purchase agreement - OVEC (a)		100		108
	Net deferred tax assets		30		34
	Act 129 compliance rider		15		8	$	15	$	8
	Defined benefit plans		26		17
	Interest rate swaps		86		14
	Other		5		9
Total noncurrent regulatory liabilities		$	1,048	$	1,010	$	15	$	8

		LKE				LG&E				KU
		2013		2012		2013		2012		2013		2012

Current Regulatory Assets:
	Environmental cost recovery	$	7	$	1	$	2	$	1	$	5
	Gas supply clause		10		11		10		11
	Fuel adjustment clause		2		6		2		6
	Demand side management		8		1		3		1		5
Total current regulatory assets		$	27	$	19	$	17	$	19	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	252	$	368	$	164	$	232	$	88	$	136
	Storm costs		94		109		51		59		43		50
	Unamortized loss on debt		28		31		18		20		10		11
	Interest rate swaps		44		67		44		67
	AROs		44		26		21		15		23		11
	Other		12		29		5		7		7		22
Total noncurrent regulatory assets		$	474	$	630	$	303	$	400	$	171	$	230

Current Regulatory Liabilities:
		Environmental cost recovery			$	4							$	4
		Gas supply clause	$	3		4	$	3	$	4
		Fuel adjustment clause		4		1					$	4		1
		Gas line tracker		6				6
		Other		1								1
Total current regulatory liabilities			$	14	$	9	$	9	$	4	$	5	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	688	$	679	$	299	$	297	$	389	$	382
	Coal contracts (a)			98		141		43		61		55		80
	Power purchase agreement - OVEC (a)			100		108		69		75		31		33
	Net deferred tax assets			30		34		26		28		4		6
	Defined benefit plans			26		17						26		17
	Interest rate swaps			86		14		43		7		43		7
	Other			5		9		2		3		3		6
Total noncurrent regulatory liabilities			$	1,033	$	1,002	$	482	$	471	$	551	$	531

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

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."

(All Registrants except PPL Energy Supply)

Defined Benefit Plans

Defined benefit plan regulatory assets and liabilities 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 generally, are amortized over the average remaining 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 $28 million for PPL, $9 million for PPL Electric, $19 million for LKE, $13 million for LG&E and $6 million for KU are expected to be amortized into net periodic defined benefit costs in 2014.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC, as applicable, 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 2040 for PPL, LKE and KU, and through 2035 for LG&E.

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 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.

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 Rate

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.

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 that 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.

Storm Damage Expense

In accordance with the PUC's December 2012 final rate case order, PPL Electric proposed the establishment of a Storm Damage Expense Rider with the PUC. The matter remains open before the PUC. Based on 2013 actual storm experience, PPL Electric established a $14 million regulatory liability at December 31, 2013 for revenues collected from customers to cover storm costs in excess of actual storm costs incurred.

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, Phase I of 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. Phase II of PPL's energy efficiency and conservation plan allows PPL Electric to recover the maximum $185 million cost of the program over the three year period beginning June 1, 2013 through May 31, 2016. 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.

(PPL, LKE, LG&E and KU)

Environmental Cost Recovery

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. 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 equity for all ECR projects included in the 2009 and 2011 compliance plans. In 2012 and 2011, LG&E and KU were authorized to receive a 10.63% return on equity for projects associated with the 2009 compliance plan and a 10.10% return on equity for projects associated with the 2011 compliance plan.

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, 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 typically 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 to generate electricity, 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 adjustment clause and, to the extent appropriate, reestablish the fuel charge included in base rates. 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.

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.

Demand Side Management

LG&E's and KU's DSM programs consist of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM provision which includes a rate recovery mechanism that provides for concurrent recovery of DSM costs, and allows for the recovery of DSM revenues from lost sales associated with the DSM programs. Additionally, LG&E and KU earn an approved return on equity for capital expenditures associated with the residential and commercial load management/demand conservation programs. The cost of DSM programs is assigned only to the class or classes of customers that benefit from the programs.

Interest Rate Swaps

(PPL, LKE, LG&E and KU)

In November 2012 and April 2013, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedged the interest payments on new debt that was expected to be issued in 2013. In September 2013, these hedges were terminated and LG&E and KU entered into new forward-starting interest rate swaps with PPL, effectively extending the start date of the prior hedges from September 2013 to December 2013. All of these swaps had terms identical to forward-starting swaps entered into by PPL with third parties. New debt totaling $500 million was issued in November 2013 (LG&E and KU each issued $250 million) and the hedges issued in September were terminated in November 2013. Net cash settlements of $86 million (LG&E and KU each received $43 million) were received on the swaps that were terminated in September and November, which are included in "Cash Flows from Operating Activities" on the Statements of Cash Flows. Net realized gains on these swaps will be returned through regulated rates. As such, the net settlements were reclassified from AOCI to regulatory liabilities and are being recognized in "Interest Expense" on the Statements of Income over the life of the newly issued debt. For the year ended December 31, 2013, there was no hedge ineffectiveness recorded for the interest rate derivatives. See Note 19 for additional information related to the forward-starting interest rate swaps.

(PPL, LKE and LG&E)

In addition to the hedges terminated as a result of the debt issuance, realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract from 2008, are recoverable through rates based on an order from the KPSC, LG&E's unrealized losses and gains 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 or loss related to the 2008 terminated swap contract is to be recovered through 2035, as approved by the KPSC.

AROs

As discussed in Note 1, the accretion and depreciation expenses related to LG&E's and KU's AROs are recorded as a regulatory asset, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset is offset against the associated cost of removal regulatory liability, PP&E and ARO liability.

Gas Line Tracker

In the 2012 rate case order, the KPSC approved the GLT rate recovery mechanism. The GLT authorizes LG&E to recover its incremental operating expenses and depreciation, and to earn a 10.25% return on equity for capital associated with the five year gas service riser and leak mitigation program. As part of this program, LG&E makes necessary repairs and assumes ownership of natural gas lines. LG&E annually files projected costs in October to become effective on the first billing cycle in January. After the completion of a plan year, LG&E submits a balancing adjustment filing to the KPSC to amend rates charged for the differences between the actual costs and actual GLT charges for the preceding year.

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.

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

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentives and penalties for the DPCR4. WPD had a $74 million liability recorded at December 31, 2013, compared with $94 million at December 31, 2012. In the fourth quarter of 2012, based on applying the preferred methodology indicated by Ofgem in a consultation issued in November 2012, the liability was reduced by $79 million with a credit recorded in "Utility" revenue on the Statement of Income. In July 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss calculation. Subsequent to the July 2013 decision paper, WPD received additional information from Ofgem. As a result, during 2013, WPD recorded increases of $45 million to the liability with reductions to "Utility" revenue on the Statement of Income. Other changes to the liability in 2013 included reductions of $66 million resulting from refunds being included in tariffs and foreign exchange movements. The potential loss exposure is estimated to be in the range of $74 million to $213 million as of December 31, 2013. PPL cannot predict the outcome of this matter.

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. 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.

Kentucky Activities

(PPL, LKE, LG&E and KU)

Rate Case Proceedings

In December 2012, the KPSC approved a rate case settlement agreement providing for increases in annual base electricity rates of $34 million for LG&E and $51 million for KU and an increase in annual base gas rates of $15 million for LG&E and authorizes a 10.25% return on equity. The approved rates became effective January 1, 2013.

(PPL, LKE and LG&E)

CPCN Filings

In January 2014, LG&E and KU filed an application for a CPCN with the KPSC requesting approval to build a NGCC generating unit at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site.

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 December 2012, the PUC approved a total distribution revenue increase of about $71 million for PPL Electric, including a 10.4% allowed return on equity. The approved rates became effective January 1, 2013.

Storm Damage Expense Rider

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER). In March 2013, PPL Electric filed its proposed SDER with the PUC and, as part of that filing, requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy. PPL Electric proposed that the SDER become effective January 1, 2013 at a zero rate with qualifying storm costs incurred in 2013 and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. In April 2013, parties filed comments opposing the SDER. PPL Electric and several other parties filed reply comments in May 2013. In November 2013, the PUC suspended the effective date of the rider to February 28, 2014 and requested additional comments and reply comments on PPL Electric's proposal. Comments and reply comments have been filed. On February 10, 2014, PPL Electric agreed to an additional suspension of the effective date of the rider to May 1, 2014. This matter remains pending before the PUC.

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 subject 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. EDCs are 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 Phase 1 EE&C Plan ending May 31, 2013.

Act 129 required EDCs to reduce overall electricity consumption by 1.0% by May 2011 and by 3.0% by May 2013, and reduce peak demand by 4.5% by May 2013. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction was required to occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. PPL Electric believes it has met the May 2011 and May 2013 overall electricity consumption requirements, and the peak demand reduction requirement based on the results of its November 15, 2013 Act 129 Final Annual Report. PPL Electric does not expect the PUC to formally determine compliance for either the 2011 or 2013 requirements until after the first quarter of 2014.

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 Phase II reduction target is 2.1% of the total energy consumption forecasted by the PUC for the twelve months ended May 31, 2010. 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, in March 2013, the PUC approved PPL Electric's Phase II EE&C Plan with minor modifications. PPL Electric filed a Revised Phase II EE&C Plan on May 13, 2013 pursuant to the PUC's March Order. On July 11, 2013, the PUC issued an Order approving PPL Electric's Revised Phase II EE&C Plan. PPL Electric began its Phase II Plan implementation on June 1, 2013. In November 2013, PPL Electric filed 40 modifications to its Phase II Plan which contains programs designed to meet PPL Electric's target of reducing total energy consumption by 2.1%. Parties have filed comments and reply comments on PPL Electric's proposal.

Act 129 also requires Default Service Providers (DSP) to provide electricity 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. A DSP is able to recover the costs associated with its default service procurement plan.

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

The PUC 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 January 2013, the PUC approved PPL Electric's plan with modifications. PPL Electric filed revised retail competition initiatives and a revised plan consistent with the PUC's January order, and in May 2013, the PUC approved that filing with minor changes. PPL Electric began implementing its revised plan on June 1, 2013. PPL Electric anticipates filing its default service procurement plan for the period beginning June 1, 2015 in the second quarter of 2014.

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 are able to recover the costs of providing smart metering technology. All of PPL Electric's metered customers currently have advanced meters installed at their service locations capable of many of the functions required under Act 129. PPL Electric continues to conduct pilot projects to evaluate additional applications of its current advanced metering technology pursuant to the requirements of Act 129. PPL Electric recovers the cost of its pilot projects through a cost recovery mechanism, the Smart Meter Rider (SMR). In August 2013, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2013 and its planned actions for 2014. PPL Electric also submitted revised SMR charges that became effective January 1, 2014. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

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 phase one 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. From December 2011 through the end of 2012, the PUC issued several orders and other pronouncements related to the investigation. A final implementation order was issued in February 2013, and the PUC created several working groups to address continuing competitive issues. 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.

Distribution System Improvement Charge

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, on January 15, 2013, PPL Electric filed a petition requesting permission to establish a DSIC. Several parties filed responses to PPL Electric's petition. In an order entered on May 23, 2013, the PUC approved PPL Electric's proposed DSIC with an initial rate effective July 1, 2013, subject to refund after hearings. The PUC also assigned four technical recovery calculation issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. The case remains pending before the PUC.

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. At December 31, 2013 and 2012, respectively, $29 million and $28 million was included on the Balance Sheets as a regulatory asset. 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 “Storm Damage Expense Rider” 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. The formula rate is calculated, in part, based on financial results as reported in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts.

PPL Electric initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update was 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 issued an order setting 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 filed a request for rehearing of the February order which remains pending before the FERC. PPL Electric and the group of municipal customers have exchanged confidential settlement proposals and PPL Electric anticipates that there will be additional settlement conferences held in 2014. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In May 2013, PPL Electric filed its 2013 Annual Update with rates proposed to become effective on June 1, 2013. The rates became effective as proposed, and no party has filed a challenge to the 2013 updated rates.

FERC Formula Rates (KU)

In May 2013, KU submitted to the FERC the annual adjustments to the formula rate, which incorporated certain proposed increases. These rates became effective as of July 1, 2013.

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides wholesale requirements power sales to 12 municipal customers. Among other changes, the application requests an amended formula whereby KU would charge cost-based rates with a subsequent true-up to actual costs, replacing the current formula which does not include such a true-up. KU's application proposed an authorized return on equity of 10.7%. Subject to regulatory approval, the new formula rate may become effective during the second quarter of 2014.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

Regulatory Assets and Liabilities

(All Registrants except PPL Energy Supply)

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.

WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities. See Note 1 for additional information.

(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 adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets.

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.

(All Registrants except PPL Energy Supply)

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

		PPL				PPL Electric
		2013		2012		2013		2012

Current Regulatory Assets:
	Environmental cost recovery	$	7	$	1
	Gas supply clause		10		11
	Fuel adjustment clause		2		6
	Demand side management		8		1
	Other		6			$	6
Total current regulatory assets		$	33	$	19	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	509	$	730	$	257	$	362
	Taxes recoverable through future rates		306		293		306		293
	Storm costs		147		168		53		59
	Unamortized loss on debt		85		96		57		65
	Interest rate swaps		44		67
	Accumulated cost of removal of utility plant		98		71		98		71
	AROs		44		26
	Other		13		32		1		3
Total noncurrent regulatory assets		$	1,246	$	1,483	$	772	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	23	$	27	$	23	$	27
	Environmental cost recovery				4
	Gas supply clause		3		4
	Transmission service charge		8		6		8		6
	Transmission formula rate		20				20
	Fuel adjustment clause		4		1
	Universal Service Rider		10		17		10		17
	Storm damage expense		14				14
	Gas line tracker		6
	Other		2		2		1		2
Total current regulatory liabilities		$	90	$	61	$	76	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	688	$	679
	Coal contracts (a)		98		141
	Power purchase agreement - OVEC (a)		100		108
	Net deferred tax assets		30		34
	Act 129 compliance rider		15		8	$	15	$	8
	Defined benefit plans		26		17
	Interest rate swaps		86		14
	Other		5		9
Total noncurrent regulatory liabilities		$	1,048	$	1,010	$	15	$	8

		LKE				LG&E				KU
		2013		2012		2013		2012		2013		2012

Current Regulatory Assets:
	Environmental cost recovery	$	7	$	1	$	2	$	1	$	5
	Gas supply clause		10		11		10		11
	Fuel adjustment clause		2		6		2		6
	Demand side management		8		1		3		1		5
Total current regulatory assets		$	27	$	19	$	17	$	19	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	252	$	368	$	164	$	232	$	88	$	136
	Storm costs		94		109		51		59		43		50
	Unamortized loss on debt		28		31		18		20		10		11
	Interest rate swaps		44		67		44		67
	AROs		44		26		21		15		23		11
	Other		12		29		5		7		7		22
Total noncurrent regulatory assets		$	474	$	630	$	303	$	400	$	171	$	230

Current Regulatory Liabilities:
		Environmental cost recovery			$	4							$	4
		Gas supply clause	$	3		4	$	3	$	4
		Fuel adjustment clause		4		1					$	4		1
		Gas line tracker		6				6
		Other		1								1
Total current regulatory liabilities			$	14	$	9	$	9	$	4	$	5	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	688	$	679	$	299	$	297	$	389	$	382
	Coal contracts (a)			98		141		43		61		55		80
	Power purchase agreement - OVEC (a)			100		108		69		75		31		33
	Net deferred tax assets			30		34		26		28		4		6
	Defined benefit plans			26		17						26		17
	Interest rate swaps			86		14		43		7		43		7
	Other			5		9		2		3		3		6
Total noncurrent regulatory liabilities			$	1,033	$	1,002	$	482	$	471	$	551	$	531

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

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."

(All Registrants except PPL Energy Supply)

Defined Benefit Plans

Defined benefit plan regulatory assets and liabilities 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 generally, are amortized over the average remaining 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 $28 million for PPL, $9 million for PPL Electric, $19 million for LKE, $13 million for LG&E and $6 million for KU are expected to be amortized into net periodic defined benefit costs in 2014.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC, as applicable, 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 2040 for PPL, LKE and KU, and through 2035 for LG&E.

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 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.

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 Rate

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.

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 that 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.

Storm Damage Expense

In accordance with the PUC's December 2012 final rate case order, PPL Electric proposed the establishment of a Storm Damage Expense Rider with the PUC. The matter remains open before the PUC. Based on 2013 actual storm experience, PPL Electric established a $14 million regulatory liability at December 31, 2013 for revenues collected from customers to cover storm costs in excess of actual storm costs incurred.

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, Phase I of 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. Phase II of PPL's energy efficiency and conservation plan allows PPL Electric to recover the maximum $185 million cost of the program over the three year period beginning June 1, 2013 through May 31, 2016. 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.

(PPL, LKE, LG&E and KU)

Environmental Cost Recovery

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. 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 equity for all ECR projects included in the 2009 and 2011 compliance plans. In 2012 and 2011, LG&E and KU were authorized to receive a 10.63% return on equity for projects associated with the 2009 compliance plan and a 10.10% return on equity for projects associated with the 2011 compliance plan.

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, 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 typically 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 to generate electricity, 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 adjustment clause and, to the extent appropriate, reestablish the fuel charge included in base rates. 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.

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.

Demand Side Management

LG&E's and KU's DSM programs consist of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM provision which includes a rate recovery mechanism that provides for concurrent recovery of DSM costs, and allows for the recovery of DSM revenues from lost sales associated with the DSM programs. Additionally, LG&E and KU earn an approved return on equity for capital expenditures associated with the residential and commercial load management/demand conservation programs. The cost of DSM programs is assigned only to the class or classes of customers that benefit from the programs.

Interest Rate Swaps

(PPL, LKE, LG&E and KU)

In November 2012 and April 2013, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedged the interest payments on new debt that was expected to be issued in 2013. In September 2013, these hedges were terminated and LG&E and KU entered into new forward-starting interest rate swaps with PPL, effectively extending the start date of the prior hedges from September 2013 to December 2013. All of these swaps had terms identical to forward-starting swaps entered into by PPL with third parties. New debt totaling $500 million was issued in November 2013 (LG&E and KU each issued $250 million) and the hedges issued in September were terminated in November 2013. Net cash settlements of $86 million (LG&E and KU each received $43 million) were received on the swaps that were terminated in September and November, which are included in "Cash Flows from Operating Activities" on the Statements of Cash Flows. Net realized gains on these swaps will be returned through regulated rates. As such, the net settlements were reclassified from AOCI to regulatory liabilities and are being recognized in "Interest Expense" on the Statements of Income over the life of the newly issued debt. For the year ended December 31, 2013, there was no hedge ineffectiveness recorded for the interest rate derivatives. See Note 19 for additional information related to the forward-starting interest rate swaps.

(PPL, LKE and LG&E)

In addition to the hedges terminated as a result of the debt issuance, realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract from 2008, are recoverable through rates based on an order from the KPSC, LG&E's unrealized losses and gains 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 or loss related to the 2008 terminated swap contract is to be recovered through 2035, as approved by the KPSC.

AROs

As discussed in Note 1, the accretion and depreciation expenses related to LG&E's and KU's AROs are recorded as a regulatory asset, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset is offset against the associated cost of removal regulatory liability, PP&E and ARO liability.

Gas Line Tracker

In the 2012 rate case order, the KPSC approved the GLT rate recovery mechanism. The GLT authorizes LG&E to recover its incremental operating expenses and depreciation, and to earn a 10.25% return on equity for capital associated with the five year gas service riser and leak mitigation program. As part of this program, LG&E makes necessary repairs and assumes ownership of natural gas lines. LG&E annually files projected costs in October to become effective on the first billing cycle in January. After the completion of a plan year, LG&E submits a balancing adjustment filing to the KPSC to amend rates charged for the differences between the actual costs and actual GLT charges for the preceding year.

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.

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

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentives and penalties for the DPCR4. WPD had a $74 million liability recorded at December 31, 2013, compared with $94 million at December 31, 2012. In the fourth quarter of 2012, based on applying the preferred methodology indicated by Ofgem in a consultation issued in November 2012, the liability was reduced by $79 million with a credit recorded in "Utility" revenue on the Statement of Income. In July 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss calculation. Subsequent to the July 2013 decision paper, WPD received additional information from Ofgem. As a result, during 2013, WPD recorded increases of $45 million to the liability with reductions to "Utility" revenue on the Statement of Income. Other changes to the liability in 2013 included reductions of $66 million resulting from refunds being included in tariffs and foreign exchange movements. The potential loss exposure is estimated to be in the range of $74 million to $213 million as of December 31, 2013. PPL cannot predict the outcome of this matter.

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. 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.

Kentucky Activities

(PPL, LKE, LG&E and KU)

Rate Case Proceedings

In December 2012, the KPSC approved a rate case settlement agreement providing for increases in annual base electricity rates of $34 million for LG&E and $51 million for KU and an increase in annual base gas rates of $15 million for LG&E and authorizes a 10.25% return on equity. The approved rates became effective January 1, 2013.

(PPL, LKE and LG&E)

CPCN Filings

In January 2014, LG&E and KU filed an application for a CPCN with the KPSC requesting approval to build a NGCC generating unit at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site.

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 December 2012, the PUC approved a total distribution revenue increase of about $71 million for PPL Electric, including a 10.4% allowed return on equity. The approved rates became effective January 1, 2013.

Storm Damage Expense Rider

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER). In March 2013, PPL Electric filed its proposed SDER with the PUC and, as part of that filing, requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy. PPL Electric proposed that the SDER become effective January 1, 2013 at a zero rate with qualifying storm costs incurred in 2013 and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. In April 2013, parties filed comments opposing the SDER. PPL Electric and several other parties filed reply comments in May 2013. In November 2013, the PUC suspended the effective date of the rider to February 28, 2014 and requested additional comments and reply comments on PPL Electric's proposal. Comments and reply comments have been filed. On February 10, 2014, PPL Electric agreed to an additional suspension of the effective date of the rider to May 1, 2014. This matter remains pending before the PUC.

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 subject 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. EDCs are 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 Phase 1 EE&C Plan ending May 31, 2013.

Act 129 required EDCs to reduce overall electricity consumption by 1.0% by May 2011 and by 3.0% by May 2013, and reduce peak demand by 4.5% by May 2013. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction was required to occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. PPL Electric believes it has met the May 2011 and May 2013 overall electricity consumption requirements, and the peak demand reduction requirement based on the results of its November 15, 2013 Act 129 Final Annual Report. PPL Electric does not expect the PUC to formally determine compliance for either the 2011 or 2013 requirements until after the first quarter of 2014.

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 Phase II reduction target is 2.1% of the total energy consumption forecasted by the PUC for the twelve months ended May 31, 2010. 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, in March 2013, the PUC approved PPL Electric's Phase II EE&C Plan with minor modifications. PPL Electric filed a Revised Phase II EE&C Plan on May 13, 2013 pursuant to the PUC's March Order. On July 11, 2013, the PUC issued an Order approving PPL Electric's Revised Phase II EE&C Plan. PPL Electric began its Phase II Plan implementation on June 1, 2013. In November 2013, PPL Electric filed 40 modifications to its Phase II Plan which contains programs designed to meet PPL Electric's target of reducing total energy consumption by 2.1%. Parties have filed comments and reply comments on PPL Electric's proposal.

Act 129 also requires Default Service Providers (DSP) to provide electricity 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. A DSP is able to recover the costs associated with its default service procurement plan.

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

The PUC 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 January 2013, the PUC approved PPL Electric's plan with modifications. PPL Electric filed revised retail competition initiatives and a revised plan consistent with the PUC's January order, and in May 2013, the PUC approved that filing with minor changes. PPL Electric began implementing its revised plan on June 1, 2013. PPL Electric anticipates filing its default service procurement plan for the period beginning June 1, 2015 in the second quarter of 2014.

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 are able to recover the costs of providing smart metering technology. All of PPL Electric's metered customers currently have advanced meters installed at their service locations capable of many of the functions required under Act 129. PPL Electric continues to conduct pilot projects to evaluate additional applications of its current advanced metering technology pursuant to the requirements of Act 129. PPL Electric recovers the cost of its pilot projects through a cost recovery mechanism, the Smart Meter Rider (SMR). In August 2013, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2013 and its planned actions for 2014. PPL Electric also submitted revised SMR charges that became effective January 1, 2014. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

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 phase one 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. From December 2011 through the end of 2012, the PUC issued several orders and other pronouncements related to the investigation. A final implementation order was issued in February 2013, and the PUC created several working groups to address continuing competitive issues. 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.

Distribution System Improvement Charge

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, on January 15, 2013, PPL Electric filed a petition requesting permission to establish a DSIC. Several parties filed responses to PPL Electric's petition. In an order entered on May 23, 2013, the PUC approved PPL Electric's proposed DSIC with an initial rate effective July 1, 2013, subject to refund after hearings. The PUC also assigned four technical recovery calculation issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. The case remains pending before the PUC.

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. At December 31, 2013 and 2012, respectively, $29 million and $28 million was included on the Balance Sheets as a regulatory asset. 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 “Storm Damage Expense Rider” 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. The formula rate is calculated, in part, based on financial results as reported in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts.

PPL Electric initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update was 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 issued an order setting 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 filed a request for rehearing of the February order which remains pending before the FERC. PPL Electric and the group of municipal customers have exchanged confidential settlement proposals and PPL Electric anticipates that there will be additional settlement conferences held in 2014. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In May 2013, PPL Electric filed its 2013 Annual Update with rates proposed to become effective on June 1, 2013. The rates became effective as proposed, and no party has filed a challenge to the 2013 updated rates.

FERC Formula Rates (KU)

In May 2013, KU submitted to the FERC the annual adjustments to the formula rate, which incorporated certain proposed increases. These rates became effective as of July 1, 2013.

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides wholesale requirements power sales to 12 municipal customers. Among other changes, the application requests an amended formula whereby KU would charge cost-based rates with a subsequent true-up to actual costs, replacing the current formula which does not include such a true-up. KU's application proposed an authorized return on equity of 10.7%. Subject to regulatory approval, the new formula rate may become effective during the second quarter of 2014.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

Regulatory Assets and Liabilities

(All Registrants except PPL Energy Supply)

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.

WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities. See Note 1 for additional information.

(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 adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets.

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.

(All Registrants except PPL Energy Supply)

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

		PPL				PPL Electric
		2013		2012		2013		2012

Current Regulatory Assets:
	Environmental cost recovery	$	7	$	1
	Gas supply clause		10		11
	Fuel adjustment clause		2		6
	Demand side management		8		1
	Other		6			$	6
Total current regulatory assets		$	33	$	19	$	6

Noncurrent Regulatory Assets:
	Defined benefit plans	$	509	$	730	$	257	$	362
	Taxes recoverable through future rates		306		293		306		293
	Storm costs		147		168		53		59
	Unamortized loss on debt		85		96		57		65
	Interest rate swaps		44		67
	Accumulated cost of removal of utility plant		98		71		98		71
	AROs		44		26
	Other		13		32		1		3
Total noncurrent regulatory assets		$	1,246	$	1,483	$	772	$	853

Current Regulatory Liabilities:
	Generation supply charge	$	23	$	27	$	23	$	27
	Environmental cost recovery				4
	Gas supply clause		3		4
	Transmission service charge		8		6		8		6
	Transmission formula rate		20				20
	Fuel adjustment clause		4		1
	Universal Service Rider		10		17		10		17
	Storm damage expense		14				14
	Gas line tracker		6
	Other		2		2		1		2
Total current regulatory liabilities		$	90	$	61	$	76	$	52

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	688	$	679
	Coal contracts (a)		98		141
	Power purchase agreement - OVEC (a)		100		108
	Net deferred tax assets		30		34
	Act 129 compliance rider		15		8	$	15	$	8
	Defined benefit plans		26		17
	Interest rate swaps		86		14
	Other		5		9
Total noncurrent regulatory liabilities		$	1,048	$	1,010	$	15	$	8

		LKE				LG&E				KU
		2013		2012		2013		2012		2013		2012

Current Regulatory Assets:
	Environmental cost recovery	$	7	$	1	$	2	$	1	$	5
	Gas supply clause		10		11		10		11
	Fuel adjustment clause		2		6		2		6
	Demand side management		8		1		3		1		5
Total current regulatory assets		$	27	$	19	$	17	$	19	$	10

Noncurrent Regulatory Assets:
	Defined benefit plans	$	252	$	368	$	164	$	232	$	88	$	136
	Storm costs		94		109		51		59		43		50
	Unamortized loss on debt		28		31		18		20		10		11
	Interest rate swaps		44		67		44		67
	AROs		44		26		21		15		23		11
	Other		12		29		5		7		7		22
Total noncurrent regulatory assets		$	474	$	630	$	303	$	400	$	171	$	230

Current Regulatory Liabilities:
		Environmental cost recovery			$	4							$	4
		Gas supply clause	$	3		4	$	3	$	4
		Fuel adjustment clause		4		1					$	4		1
		Gas line tracker		6				6
		Other		1								1
Total current regulatory liabilities			$	14	$	9	$	9	$	4	$	5	$	5

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	688	$	679	$	299	$	297	$	389	$	382
	Coal contracts (a)			98		141		43		61		55		80
	Power purchase agreement - OVEC (a)			100		108		69		75		31		33
	Net deferred tax assets			30		34		26		28		4		6
	Defined benefit plans			26		17						26		17
	Interest rate swaps			86		14		43		7		43		7
	Other			5		9		2		3		3		6
Total noncurrent regulatory liabilities			$	1,033	$	1,002	$	482	$	471	$	551	$	531

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

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."

(All Registrants except PPL Energy Supply)

Defined Benefit Plans

Defined benefit plan regulatory assets and liabilities 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 generally, are amortized over the average remaining 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 $28 million for PPL, $9 million for PPL Electric, $19 million for LKE, $13 million for LG&E and $6 million for KU are expected to be amortized into net periodic defined benefit costs in 2014.

Storm Costs

PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC, as applicable, 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 2040 for PPL, LKE and KU, and through 2035 for LG&E.

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 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.

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 Rate

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.

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 that 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.

Storm Damage Expense

In accordance with the PUC's December 2012 final rate case order, PPL Electric proposed the establishment of a Storm Damage Expense Rider with the PUC. The matter remains open before the PUC. Based on 2013 actual storm experience, PPL Electric established a $14 million regulatory liability at December 31, 2013 for revenues collected from customers to cover storm costs in excess of actual storm costs incurred.

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, Phase I of 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. Phase II of PPL's energy efficiency and conservation plan allows PPL Electric to recover the maximum $185 million cost of the program over the three year period beginning June 1, 2013 through May 31, 2016. 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.

(PPL, LKE, LG&E and KU)

Environmental Cost Recovery

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. 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 equity for all ECR projects included in the 2009 and 2011 compliance plans. In 2012 and 2011, LG&E and KU were authorized to receive a 10.63% return on equity for projects associated with the 2009 compliance plan and a 10.10% return on equity for projects associated with the 2011 compliance plan.

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, 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 typically 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 to generate electricity, 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 adjustment clause and, to the extent appropriate, reestablish the fuel charge included in base rates. 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.

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.

Demand Side Management

LG&E's and KU's DSM programs consist of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM provision which includes a rate recovery mechanism that provides for concurrent recovery of DSM costs, and allows for the recovery of DSM revenues from lost sales associated with the DSM programs. Additionally, LG&E and KU earn an approved return on equity for capital expenditures associated with the residential and commercial load management/demand conservation programs. The cost of DSM programs is assigned only to the class or classes of customers that benefit from the programs.

Interest Rate Swaps

(PPL, LKE, LG&E and KU)

In November 2012 and April 2013, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedged the interest payments on new debt that was expected to be issued in 2013. In September 2013, these hedges were terminated and LG&E and KU entered into new forward-starting interest rate swaps with PPL, effectively extending the start date of the prior hedges from September 2013 to December 2013. All of these swaps had terms identical to forward-starting swaps entered into by PPL with third parties. New debt totaling $500 million was issued in November 2013 (LG&E and KU each issued $250 million) and the hedges issued in September were terminated in November 2013. Net cash settlements of $86 million (LG&E and KU each received $43 million) were received on the swaps that were terminated in September and November, which are included in "Cash Flows from Operating Activities" on the Statements of Cash Flows. Net realized gains on these swaps will be returned through regulated rates. As such, the net settlements were reclassified from AOCI to regulatory liabilities and are being recognized in "Interest Expense" on the Statements of Income over the life of the newly issued debt. For the year ended December 31, 2013, there was no hedge ineffectiveness recorded for the interest rate derivatives. See Note 19 for additional information related to the forward-starting interest rate swaps.

(PPL, LKE and LG&E)

In addition to the hedges terminated as a result of the debt issuance, realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract from 2008, are recoverable through rates based on an order from the KPSC, LG&E's unrealized losses and gains 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 or loss related to the 2008 terminated swap contract is to be recovered through 2035, as approved by the KPSC.

AROs

As discussed in Note 1, the accretion and depreciation expenses related to LG&E's and KU's AROs are recorded as a regulatory asset, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset is offset against the associated cost of removal regulatory liability, PP&E and ARO liability.

Gas Line Tracker

In the 2012 rate case order, the KPSC approved the GLT rate recovery mechanism. The GLT authorizes LG&E to recover its incremental operating expenses and depreciation, and to earn a 10.25% return on equity for capital associated with the five year gas service riser and leak mitigation program. As part of this program, LG&E makes necessary repairs and assumes ownership of natural gas lines. LG&E annually files projected costs in October to become effective on the first billing cycle in January. After the completion of a plan year, LG&E submits a balancing adjustment filing to the KPSC to amend rates charged for the differences between the actual costs and actual GLT charges for the preceding year.

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.

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

U.K. Activities (PPL)

Ofgem Review of Line Loss Calculation

Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentives and penalties for the DPCR4. WPD had a $74 million liability recorded at December 31, 2013, compared with $94 million at December 31, 2012. In the fourth quarter of 2012, based on applying the preferred methodology indicated by Ofgem in a consultation issued in November 2012, the liability was reduced by $79 million with a credit recorded in "Utility" revenue on the Statement of Income. In July 2013, Ofgem issued a decision paper on the process to follow for closing out the line loss calculation. Subsequent to the July 2013 decision paper, WPD received additional information from Ofgem. As a result, during 2013, WPD recorded increases of $45 million to the liability with reductions to "Utility" revenue on the Statement of Income. Other changes to the liability in 2013 included reductions of $66 million resulting from refunds being included in tariffs and foreign exchange movements. The potential loss exposure is estimated to be in the range of $74 million to $213 million as of December 31, 2013. PPL cannot predict the outcome of this matter.

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. 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.

Kentucky Activities

(PPL, LKE, LG&E and KU)

Rate Case Proceedings

In December 2012, the KPSC approved a rate case settlement agreement providing for increases in annual base electricity rates of $34 million for LG&E and $51 million for KU and an increase in annual base gas rates of $15 million for LG&E and authorizes a 10.25% return on equity. The approved rates became effective January 1, 2013.

(PPL, LKE and LG&E)

CPCN Filings

In January 2014, LG&E and KU filed an application for a CPCN with the KPSC requesting approval to build a NGCC generating unit at KU's Green River generating site and a solar generating facility at the E. W. Brown generating site.

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 December 2012, the PUC approved a total distribution revenue increase of about $71 million for PPL Electric, including a 10.4% allowed return on equity. The approved rates became effective January 1, 2013.

Storm Damage Expense Rider

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider (SDER). In March 2013, PPL Electric filed its proposed SDER with the PUC and, as part of that filing, requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy. PPL Electric proposed that the SDER become effective January 1, 2013 at a zero rate with qualifying storm costs incurred in 2013 and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. In April 2013, parties filed comments opposing the SDER. PPL Electric and several other parties filed reply comments in May 2013. In November 2013, the PUC suspended the effective date of the rider to February 28, 2014 and requested additional comments and reply comments on PPL Electric's proposal. Comments and reply comments have been filed. On February 10, 2014, PPL Electric agreed to an additional suspension of the effective date of the rider to May 1, 2014. This matter remains pending before the PUC.

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 subject 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. EDCs are 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 Phase 1 EE&C Plan ending May 31, 2013.

Act 129 required EDCs to reduce overall electricity consumption by 1.0% by May 2011 and by 3.0% by May 2013, and reduce peak demand by 4.5% by May 2013. The overall consumption reduction is measured against PUC-forecasted consumption for the twelve months ended May 31, 2010. The peak demand reduction was required to occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. PPL Electric believes it has met the May 2011 and May 2013 overall electricity consumption requirements, and the peak demand reduction requirement based on the results of its November 15, 2013 Act 129 Final Annual Report. PPL Electric does not expect the PUC to formally determine compliance for either the 2011 or 2013 requirements until after the first quarter of 2014.

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 Phase II reduction target is 2.1% of the total energy consumption forecasted by the PUC for the twelve months ended May 31, 2010. 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, in March 2013, the PUC approved PPL Electric's Phase II EE&C Plan with minor modifications. PPL Electric filed a Revised Phase II EE&C Plan on May 13, 2013 pursuant to the PUC's March Order. On July 11, 2013, the PUC issued an Order approving PPL Electric's Revised Phase II EE&C Plan. PPL Electric began its Phase II Plan implementation on June 1, 2013. In November 2013, PPL Electric filed 40 modifications to its Phase II Plan which contains programs designed to meet PPL Electric's target of reducing total energy consumption by 2.1%. Parties have filed comments and reply comments on PPL Electric's proposal.

Act 129 also requires Default Service Providers (DSP) to provide electricity 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. A DSP is able to recover the costs associated with its default service procurement plan.

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

The PUC 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 January 2013, the PUC approved PPL Electric's plan with modifications. PPL Electric filed revised retail competition initiatives and a revised plan consistent with the PUC's January order, and in May 2013, the PUC approved that filing with minor changes. PPL Electric began implementing its revised plan on June 1, 2013. PPL Electric anticipates filing its default service procurement plan for the period beginning June 1, 2015 in the second quarter of 2014.

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 are able to recover the costs of providing smart metering technology. All of PPL Electric's metered customers currently have advanced meters installed at their service locations capable of many of the functions required under Act 129. PPL Electric continues to conduct pilot projects to evaluate additional applications of its current advanced metering technology pursuant to the requirements of Act 129. PPL Electric recovers the cost of its pilot projects through a cost recovery mechanism, the Smart Meter Rider (SMR). In August 2013, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2013 and its planned actions for 2014. PPL Electric also submitted revised SMR charges that became effective January 1, 2014. PPL Electric will submit its final Smart Meter Plan by June 30, 2014.

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 phase one 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. From December 2011 through the end of 2012, the PUC issued several orders and other pronouncements related to the investigation. A final implementation order was issued in February 2013, and the PUC created several working groups to address continuing competitive issues. 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.

Distribution System Improvement Charge

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, on January 15, 2013, PPL Electric filed a petition requesting permission to establish a DSIC. Several parties filed responses to PPL Electric's petition. In an order entered on May 23, 2013, the PUC approved PPL Electric's proposed DSIC with an initial rate effective July 1, 2013, subject to refund after hearings. The PUC also assigned four technical recovery calculation issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. The case remains pending before the PUC.

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. At December 31, 2013 and 2012, respectively, $29 million and $28 million was included on the Balance Sheets as a regulatory asset. 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 “Storm Damage Expense Rider” 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. The formula rate is calculated, in part, based on financial results as reported in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts.

PPL Electric initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update was 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 issued an order setting 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 filed a request for rehearing of the February order which remains pending before the FERC. PPL Electric and the group of municipal customers have exchanged confidential settlement proposals and PPL Electric anticipates that there will be additional settlement conferences held in 2014. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In May 2013, PPL Electric filed its 2013 Annual Update with rates proposed to become effective on June 1, 2013. The rates became effective as proposed, and no party has filed a challenge to the 2013 updated rates.

FERC Formula Rates (KU)

In May 2013, KU submitted to the FERC the annual adjustments to the formula rate, which incorporated certain proposed increases. These rates became effective as of July 1, 2013.

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides wholesale requirements power sales to 12 municipal customers. Among other changes, the application requests an amended formula whereby KU would charge cost-based rates with a subsequent true-up to actual costs, replacing the current formula which does not include such a true-up. KU's application proposed an authorized return on equity of 10.7%. Subject to regulatory approval, the new formula rate may become effective during the second quarter of 2014.