6. Utility Rate Regulation

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

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

		PPL				PPL Electric
		September 30,		December 31,		September 30,		December 31,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	6	$	6
	Fuel adjustment clause		13		3
	Other		2
Total current regulatory assets		$	21	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	583	$	615	$	266	$	276
	Taxes recoverable through future rates		299		289		299		289
	Storm costs		143		154		31		31
	Unamortized loss on debt		99		110		68		77
	Interest rate swaps		71		69
	Accumulated cost of removal of utility plant		67		53		67		53
	Coal contracts (a)		5		11
	AROs		26		18
	Other		30		30		2		3
Total noncurrent regulatory assets		$	1,323	$	1,349	$	733	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	24	$	42	$	24	$	42
	ECR		7		7
	Gas supply clause		5		6
	Transmission service charge		5		2		5		2
	Transmission formula rate		8		5		8		5
	Universal service rider		12		1		12		1
	Other		4		10		3		3
Total current regulatory liabilities		$	65	$	73	$	52	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	673	$	651
	Coal contracts (a)		151		180
	Power purchase agreement - OVEC (a)		110		116
	Net deferred tax assets		35		39
	Act 129 compliance rider		12		7	$	12	$	7
	Defined benefit plans		10		9
	Other		8		8
Total noncurrent regulatory liabilities		$	999	$	1,010	$	12	$	7

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	6	$	6	$	6	$	6
	Fuel adjustment clause		13		3		10		3	$	3
	Other		2				1				1
Total current regulatory assets		$	21	$	9	$	17	$	9	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	317	$	339	$	210	$	225	$	107	$	114
	Storm costs		112		123		61		66		51		57
	Unamortized loss on debt		31		33		20		21		11		12
	Interest rate swaps		71		69		71		69
	Coal contracts (a)		5		11		2		5		3		6
	AROs		26		18		14		11		12		7
	Other		28		27		6		6		22		21
Total noncurrent regulatory assets		$	590	$	620	$	384	$	403	$	206	$	217

Current Regulatory Liabilities:
		ECR	$	7	$	7					$	7	$	7
		Gas supply clause		5		6	$	5	$	6
		Other		1		7				4		1		3
Total current regulatory liabilities			$	13	$	20	$	5	$	10	$	8	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	673	$	651	$	294	$	286	$	379	$	365
	Coal contracts (a)			151		180		66		78		85		102
	Power purchase agreement - OVEC (a)			110		116		76		80		34		36
	Net deferred tax assets			35		39		28		31		7		8
	Defined benefit plans			10		9						10		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	987	$	1,003	$	467	$	478	$	520	$	525

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

Regulatory Matters

Kentucky Activities (PPL, LKE, LG&E and KU)

CPCN Filing

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. In May 2012, the KPSC issued an order approving the request to build the NGCC. LG&E will own a 22% undivided interest and KU will own a 78% undivided interest in the new NGCC. A formal request for recovery of the costs associated with the NGCC construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. See Note 8 for additional information.

In conjunction with this construction and to meet new, stricter EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant, one coal-fired generating unit at KU's Tyrone plant and two coal-fired generating units at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

The CPCN application also requested approval to purchase the Bluegrass CTs. The May 2012 KPSC approval included authority to complete the Bluegrass CT acquisition. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC. LG&E and KU are currently assessing the impact of the asset purchase agreement termination and potential future generation capacity options. See Note 8 for additional information.

Kentucky Acquisition Commitments

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect, currently expected to be 2013. Therefore, due to the timing of the current rate case in Kentucky, no further ASSD filings are expected.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. The proposed base rate increases would result in electric rate increases of 6.9% at LG&E and 6.5% at KU and a gas rate increase of 7.0% at LG&E and would be effective in January 2013. LG&E's and KU's applications include requests for authorized returns-on-equity at LG&E and KU of 11% each. In November 2012, the KPSC issued an order for a settlement conference to begin on November 13, 2012. A hearing on the original application and subsequent testimony is scheduled to begin on November 27, 2012. LG&E and KU cannot predict the outcome of these proceedings, including the possibility of any agreed stipulations or settlement, which would remain subject to KPSC approval. A final order may be issued in December 2012 or January 2013.

Independent Transmission Operators

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

Storm Costs (PPL, LKE and LG&E)

In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011, requesting approval of a regulatory asset recorded to defer, for future recovery, $7 million in incremental operation and maintenance expenses related to the storm restoration. An order was received in December 2011 granting the request, while the recovery of the regulatory asset will be determined within the current base rate case discussed above in “Rate Case Proceedings”.

Pennsylvania Activities

(PPL and PPL Electric)

PUC Investigation of Retail Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. In December 2011, the PUC issued a final order providing guidance to Electric Distribution Companies (EDCs) on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC is expected to issue a tentative implementation order in early November 2012, following which parties will have 30 days to provide comment. A final implementation order is expected to be issued in the first quarter of 2013. PPL and PPL Electric cannot predict the outcome of the investigation or its impact on their financial condition, or results of operations.

Legislation - Regulatory Procedures and Mechanisms

In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation authorizing the PUC to approve regulatory procedures and mechanisms to provide more timely recovery of a utility's costs. In the first quarter of 2012, the Governor signed an amended version of the legislation (Act 11 of 2012), which became effective April 14, 2012. The legislation authorizes the PUC to approve two specific ratemaking mechanisms -- a fully projected future test year and, subject to certain conditions, a distribution system improvements charge (DSIC). Such alternative ratemaking procedures and mechanisms 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 of 2012. In September 2012, PPL Electric filed its Long Term Infrastructure Improvement Plan (LTIIP) describing projects eligible for inclusion in the DSIC. In October 2012, several parties filed comments to the LTIIP but none of the comments requested evidentiary hearings on the LTIIP. A decision on the LTIIP is expected in January 2013. PPL Electric expects to file a petition requesting permission to establish a DSIC in January 2013, with rates proposed to be effective in April 2013.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. The proposed distribution rate increase would result in a 2.9% increase over PPL Electric's total rates at the time of the request. PPL Electric's application includes a request for an authorized return on equity of 11.25%. On October 19, 2012, the presiding Administrative Law Judge (ALJ) issued a decision recommending a rate increase of approximately $64 million, which represents an allowed return on equity of 9.74%. Exceptions to the ALJ's recommendation are due November 8, 2012. PPL Electric expects to file exceptions, together with certain other parties, to the ALJ's recommended decision. The PUC, which is expected to issue its order on the rate request in December 2012, can accept, reject or modify the ALJ's recommendation. PPL and PPL Electric cannot predict the outcome of this proceeding.

ACT 129

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

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to reduce overall electricity consumption by 1.0% by May 2011 and 3.0% by May 2013, and reduce peak demand by 4.5% for the 100 hours of highest demand by May 2013 (which is determined by actual demand reduction during the June 2012 through September 2012 period). EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. The PUC has confirmed that PPL Electric has met the 2011 requirement.

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 March 2012, the PUC began the process of designing Phase II of the EE&C program. 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 consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish any demand reduction targets for the Phase II program. In August 2012 PPL Electric filed a Petition for Reconsideration of the PUC's Order, which the PUC denied. In August 2012, PPL Electric also filed a Petition for an Evidentiary Hearing regarding its consumption reduction target. The PUC assigned the petition to an ALJ. A hearing on the petition was held on October 18, 2012. The ALJ will certify the record of the hearing to the PUC for a decision. EDCs must file Phase II plans with the PUC by November 15, 2012. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings.

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

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

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. The PUC assigned PPL Electric's plan to an ALJ. Hearings were held in September 2012 and a recommended decision is expected in the fourth quarter of 2012. The PUC is expected to rule on the plan in early 2013.

Storm Costs

PPL Electric experienced several PUC-reportable storms during the three and nine months ended September 30, 2011 resulting in total restoration costs of $34 million and $59 million, of which $23 million and $39 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms exceeded policy limits. Probable recoveries on insurance claims of $26.5 million were recorded at September 30, 2011, of which $7 million and $16 million were recorded during the three and nine months ended September 30, 2011 in "Other operation and maintenance" on the Statement of Income, with the remainder recorded in PP&E on the Balance Sheet. 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. In the recommended decision in the distribution rate proceeding discussed above in "Pennsylvania Activities - Rate Case Proceeding," the presiding ALJ recommended that PPL Electric be allowed to recover deferred storm costs of approximately $27 million over a five-year period. The PUC, which is expected to issue its order in December 2012, can accept, reject or modify the ALJ's recommendation. New rates will become effective on January 1, 2013. PPL and PPL Electric cannot predict the outcome of this proceeding. In 2012, PPL Electric increased the deductible under its insurance policy to $15.75 million and, therefore, would only request insurance recovery of reportable storm costs exceeding that amount. During the three and nine months ended September 30, 2012, PPL Electric incurred $13 million in restoration costs, of which $9 million was recorded in "Other operation and maintenance" on the Statement of Income.

In late October 2012, PPL Electric experienced widespread significant damage to its transmission and distribution network from Hurricane Sandy. The total costs associated with the restoration efforts are still being finalized but are estimated to be in excess of $60 million. PPL Electric has insurance coverage that could cover a portion of the costs incurred from Hurricane Sandy. PPL Electric will have the ability to file a request with the PUC for permission to defer for future recovery certain of the costs incurred to repair the distribution network in excess of the insurance coverage. Costs incurred to repair the transmission network are recoverable through the FERC Formula Rate mechanism which is updated annually.

Transmission Service Charge Adjustment (PPL Electric)

During the three and nine months ended September 30, 2011, PPL Electric recorded a $7 million ($4 million after-tax) charge to "Retail electric" revenue on the Statement of Income to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC. The impact of this charge was not material to any previously reported financial statements and was not material to the financial statements for the full year of 2011.

Federal Matters (PPL and PPL Electric)

FERC Formula Rates

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.

In May 2010, PPL Electric initiated its formula rate 2010 Annual Update. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.

In May 2011, PPL Electric initiated its formula rate 2011 Annual Update. In October 2011, the group of municipal customers filed a preliminary challenge to the update and, in December 2011, filed a formal challenge. In January 2012, PPL Electric filed a response to that formal challenge. In September 2012, the FERC issued an order setting for evidentiary hearings a number of issues raised in the 2010 formal challenge and a number of issues raised in the 2011 formal challenge. The FERC held the hearings in abeyance for settlement judge proceedings and assigned a settlement judge. PPL Electric filed a request for rehearing of the September 2012 order in late October 2012. An initial settlement meeting will be scheduled in November 2012.

In May 2012, PPL Electric initiated its formula rate 2012 Annual Update which currently is in the 180-day review and challenge period. In October 2012, the group of municipal customers filed a preliminary challenge to the 2012 Annual Update. PPL Electric will meet with representatives of the customers in an attempt to resolve the challenge. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of approximately $50 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheets at September 30, 2012 and December 31, 2011. In May 2012, the FERC issued an order approving PPL Electric's request effective June 1, 2012.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $172 million liability recorded at September 30, 2012 compared with $170 million at December 31, 2011, calculated in accordance with Ofgem's accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013 together with a proposal to remove the line loss incentive/penalty for DPCR5. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 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, subject to approval by the European Commission of final technical standards, is expected to become effective in January 2013. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

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

		PPL				PPL Electric
		September 30,		December 31,		September 30,		December 31,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	6	$	6
	Fuel adjustment clause		13		3
	Other		2
Total current regulatory assets		$	21	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	583	$	615	$	266	$	276
	Taxes recoverable through future rates		299		289		299		289
	Storm costs		143		154		31		31
	Unamortized loss on debt		99		110		68		77
	Interest rate swaps		71		69
	Accumulated cost of removal of utility plant		67		53		67		53
	Coal contracts (a)		5		11
	AROs		26		18
	Other		30		30		2		3
Total noncurrent regulatory assets		$	1,323	$	1,349	$	733	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	24	$	42	$	24	$	42
	ECR		7		7
	Gas supply clause		5		6
	Transmission service charge		5		2		5		2
	Transmission formula rate		8		5		8		5
	Universal service rider		12		1		12		1
	Other		4		10		3		3
Total current regulatory liabilities		$	65	$	73	$	52	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	673	$	651
	Coal contracts (a)		151		180
	Power purchase agreement - OVEC (a)		110		116
	Net deferred tax assets		35		39
	Act 129 compliance rider		12		7	$	12	$	7
	Defined benefit plans		10		9
	Other		8		8
Total noncurrent regulatory liabilities		$	999	$	1,010	$	12	$	7

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	6	$	6	$	6	$	6
	Fuel adjustment clause		13		3		10		3	$	3
	Other		2				1				1
Total current regulatory assets		$	21	$	9	$	17	$	9	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	317	$	339	$	210	$	225	$	107	$	114
	Storm costs		112		123		61		66		51		57
	Unamortized loss on debt		31		33		20		21		11		12
	Interest rate swaps		71		69		71		69
	Coal contracts (a)		5		11		2		5		3		6
	AROs		26		18		14		11		12		7
	Other		28		27		6		6		22		21
Total noncurrent regulatory assets		$	590	$	620	$	384	$	403	$	206	$	217

Current Regulatory Liabilities:
		ECR	$	7	$	7					$	7	$	7
		Gas supply clause		5		6	$	5	$	6
		Other		1		7				4		1		3
Total current regulatory liabilities			$	13	$	20	$	5	$	10	$	8	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	673	$	651	$	294	$	286	$	379	$	365
	Coal contracts (a)			151		180		66		78		85		102
	Power purchase agreement - OVEC (a)			110		116		76		80		34		36
	Net deferred tax assets			35		39		28		31		7		8
	Defined benefit plans			10		9						10		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	987	$	1,003	$	467	$	478	$	520	$	525

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

Regulatory Matters

Kentucky Activities (PPL, LKE, LG&E and KU)

CPCN Filing

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. In May 2012, the KPSC issued an order approving the request to build the NGCC. LG&E will own a 22% undivided interest and KU will own a 78% undivided interest in the new NGCC. A formal request for recovery of the costs associated with the NGCC construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. See Note 8 for additional information.

In conjunction with this construction and to meet new, stricter EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant, one coal-fired generating unit at KU's Tyrone plant and two coal-fired generating units at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

The CPCN application also requested approval to purchase the Bluegrass CTs. The May 2012 KPSC approval included authority to complete the Bluegrass CT acquisition. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC. LG&E and KU are currently assessing the impact of the asset purchase agreement termination and potential future generation capacity options. See Note 8 for additional information.

Kentucky Acquisition Commitments

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect, currently expected to be 2013. Therefore, due to the timing of the current rate case in Kentucky, no further ASSD filings are expected.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. The proposed base rate increases would result in electric rate increases of 6.9% at LG&E and 6.5% at KU and a gas rate increase of 7.0% at LG&E and would be effective in January 2013. LG&E's and KU's applications include requests for authorized returns-on-equity at LG&E and KU of 11% each. In November 2012, the KPSC issued an order for a settlement conference to begin on November 13, 2012. A hearing on the original application and subsequent testimony is scheduled to begin on November 27, 2012. LG&E and KU cannot predict the outcome of these proceedings, including the possibility of any agreed stipulations or settlement, which would remain subject to KPSC approval. A final order may be issued in December 2012 or January 2013.

Independent Transmission Operators

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

Storm Costs (PPL, LKE and LG&E)

In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011, requesting approval of a regulatory asset recorded to defer, for future recovery, $7 million in incremental operation and maintenance expenses related to the storm restoration. An order was received in December 2011 granting the request, while the recovery of the regulatory asset will be determined within the current base rate case discussed above in “Rate Case Proceedings”.

Pennsylvania Activities

(PPL and PPL Electric)

PUC Investigation of Retail Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. In December 2011, the PUC issued a final order providing guidance to Electric Distribution Companies (EDCs) on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC is expected to issue a tentative implementation order in early November 2012, following which parties will have 30 days to provide comment. A final implementation order is expected to be issued in the first quarter of 2013. PPL and PPL Electric cannot predict the outcome of the investigation or its impact on their financial condition, or results of operations.

Legislation - Regulatory Procedures and Mechanisms

In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation authorizing the PUC to approve regulatory procedures and mechanisms to provide more timely recovery of a utility's costs. In the first quarter of 2012, the Governor signed an amended version of the legislation (Act 11 of 2012), which became effective April 14, 2012. The legislation authorizes the PUC to approve two specific ratemaking mechanisms -- a fully projected future test year and, subject to certain conditions, a distribution system improvements charge (DSIC). Such alternative ratemaking procedures and mechanisms 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 of 2012. In September 2012, PPL Electric filed its Long Term Infrastructure Improvement Plan (LTIIP) describing projects eligible for inclusion in the DSIC. In October 2012, several parties filed comments to the LTIIP but none of the comments requested evidentiary hearings on the LTIIP. A decision on the LTIIP is expected in January 2013. PPL Electric expects to file a petition requesting permission to establish a DSIC in January 2013, with rates proposed to be effective in April 2013.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. The proposed distribution rate increase would result in a 2.9% increase over PPL Electric's total rates at the time of the request. PPL Electric's application includes a request for an authorized return on equity of 11.25%. On October 19, 2012, the presiding Administrative Law Judge (ALJ) issued a decision recommending a rate increase of approximately $64 million, which represents an allowed return on equity of 9.74%. Exceptions to the ALJ's recommendation are due November 8, 2012. PPL Electric expects to file exceptions, together with certain other parties, to the ALJ's recommended decision. The PUC, which is expected to issue its order on the rate request in December 2012, can accept, reject or modify the ALJ's recommendation. PPL and PPL Electric cannot predict the outcome of this proceeding.

ACT 129

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

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to reduce overall electricity consumption by 1.0% by May 2011 and 3.0% by May 2013, and reduce peak demand by 4.5% for the 100 hours of highest demand by May 2013 (which is determined by actual demand reduction during the June 2012 through September 2012 period). EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. The PUC has confirmed that PPL Electric has met the 2011 requirement.

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 March 2012, the PUC began the process of designing Phase II of the EE&C program. 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 consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish any demand reduction targets for the Phase II program. In August 2012 PPL Electric filed a Petition for Reconsideration of the PUC's Order, which the PUC denied. In August 2012, PPL Electric also filed a Petition for an Evidentiary Hearing regarding its consumption reduction target. The PUC assigned the petition to an ALJ. A hearing on the petition was held on October 18, 2012. The ALJ will certify the record of the hearing to the PUC for a decision. EDCs must file Phase II plans with the PUC by November 15, 2012. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings.

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

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

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. The PUC assigned PPL Electric's plan to an ALJ. Hearings were held in September 2012 and a recommended decision is expected in the fourth quarter of 2012. The PUC is expected to rule on the plan in early 2013.

Storm Costs

PPL Electric experienced several PUC-reportable storms during the three and nine months ended September 30, 2011 resulting in total restoration costs of $34 million and $59 million, of which $23 million and $39 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms exceeded policy limits. Probable recoveries on insurance claims of $26.5 million were recorded at September 30, 2011, of which $7 million and $16 million were recorded during the three and nine months ended September 30, 2011 in "Other operation and maintenance" on the Statement of Income, with the remainder recorded in PP&E on the Balance Sheet. 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. In the recommended decision in the distribution rate proceeding discussed above in "Pennsylvania Activities - Rate Case Proceeding," the presiding ALJ recommended that PPL Electric be allowed to recover deferred storm costs of approximately $27 million over a five-year period. The PUC, which is expected to issue its order in December 2012, can accept, reject or modify the ALJ's recommendation. New rates will become effective on January 1, 2013. PPL and PPL Electric cannot predict the outcome of this proceeding. In 2012, PPL Electric increased the deductible under its insurance policy to $15.75 million and, therefore, would only request insurance recovery of reportable storm costs exceeding that amount. During the three and nine months ended September 30, 2012, PPL Electric incurred $13 million in restoration costs, of which $9 million was recorded in "Other operation and maintenance" on the Statement of Income.

In late October 2012, PPL Electric experienced widespread significant damage to its transmission and distribution network from Hurricane Sandy. The total costs associated with the restoration efforts are still being finalized but are estimated to be in excess of $60 million. PPL Electric has insurance coverage that could cover a portion of the costs incurred from Hurricane Sandy. PPL Electric will have the ability to file a request with the PUC for permission to defer for future recovery certain of the costs incurred to repair the distribution network in excess of the insurance coverage. Costs incurred to repair the transmission network are recoverable through the FERC Formula Rate mechanism which is updated annually.

Transmission Service Charge Adjustment (PPL Electric)

During the three and nine months ended September 30, 2011, PPL Electric recorded a $7 million ($4 million after-tax) charge to "Retail electric" revenue on the Statement of Income to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC. The impact of this charge was not material to any previously reported financial statements and was not material to the financial statements for the full year of 2011.

Federal Matters (PPL and PPL Electric)

FERC Formula Rates

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.

In May 2010, PPL Electric initiated its formula rate 2010 Annual Update. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.

In May 2011, PPL Electric initiated its formula rate 2011 Annual Update. In October 2011, the group of municipal customers filed a preliminary challenge to the update and, in December 2011, filed a formal challenge. In January 2012, PPL Electric filed a response to that formal challenge. In September 2012, the FERC issued an order setting for evidentiary hearings a number of issues raised in the 2010 formal challenge and a number of issues raised in the 2011 formal challenge. The FERC held the hearings in abeyance for settlement judge proceedings and assigned a settlement judge. PPL Electric filed a request for rehearing of the September 2012 order in late October 2012. An initial settlement meeting will be scheduled in November 2012.

In May 2012, PPL Electric initiated its formula rate 2012 Annual Update which currently is in the 180-day review and challenge period. In October 2012, the group of municipal customers filed a preliminary challenge to the 2012 Annual Update. PPL Electric will meet with representatives of the customers in an attempt to resolve the challenge. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of approximately $50 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheets at September 30, 2012 and December 31, 2011. In May 2012, the FERC issued an order approving PPL Electric's request effective June 1, 2012.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $172 million liability recorded at September 30, 2012 compared with $170 million at December 31, 2011, calculated in accordance with Ofgem's accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013 together with a proposal to remove the line loss incentive/penalty for DPCR5. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 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, subject to approval by the European Commission of final technical standards, is expected to become effective in January 2013. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.

Utility Rate Regulation [Line Items]

Utility Rate Regulation

6. Utility Rate Regulation

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

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

		PPL				PPL Electric
		September 30,		December 31,		September 30,		December 31,
		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	6	$	6
	Fuel adjustment clause		13		3
	Other		2
Total current regulatory assets		$	21	$	9

Noncurrent Regulatory Assets:
	Defined benefit plans	$	583	$	615	$	266	$	276
	Taxes recoverable through future rates		299		289		299		289
	Storm costs		143		154		31		31
	Unamortized loss on debt		99		110		68		77
	Interest rate swaps		71		69
	Accumulated cost of removal of utility plant		67		53		67		53
	Coal contracts (a)		5		11
	AROs		26		18
	Other		30		30		2		3
Total noncurrent regulatory assets		$	1,323	$	1,349	$	733	$	729

Current Regulatory Liabilities:
	Generation supply charge	$	24	$	42	$	24	$	42
	ECR		7		7
	Gas supply clause		5		6
	Transmission service charge		5		2		5		2
	Transmission formula rate		8		5		8		5
	Universal service rider		12		1		12		1
	Other		4		10		3		3
Total current regulatory liabilities		$	65	$	73	$	52	$	53

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal of utility plant	$	673	$	651
	Coal contracts (a)		151		180
	Power purchase agreement - OVEC (a)		110		116
	Net deferred tax assets		35		39
	Act 129 compliance rider		12		7	$	12	$	7
	Defined benefit plans		10		9
	Other		8		8
Total noncurrent regulatory liabilities		$	999	$	1,010	$	12	$	7

		LKE				LG&E				KU
		September 30,		December 31,		September 30,		December 31,		September 30,		December 31,
		2012		2011		2012		2011		2012		2011

Current Regulatory Assets:
	Gas supply clause	$	6	$	6	$	6	$	6
	Fuel adjustment clause		13		3		10		3	$	3
	Other		2				1				1
Total current regulatory assets		$	21	$	9	$	17	$	9	$	4

Noncurrent Regulatory Assets:
	Defined benefit plans	$	317	$	339	$	210	$	225	$	107	$	114
	Storm costs		112		123		61		66		51		57
	Unamortized loss on debt		31		33		20		21		11		12
	Interest rate swaps		71		69		71		69
	Coal contracts (a)		5		11		2		5		3		6
	AROs		26		18		14		11		12		7
	Other		28		27		6		6		22		21
Total noncurrent regulatory assets		$	590	$	620	$	384	$	403	$	206	$	217

Current Regulatory Liabilities:
		ECR	$	7	$	7					$	7	$	7
		Gas supply clause		5		6	$	5	$	6
		Other		1		7				4		1		3
Total current regulatory liabilities			$	13	$	20	$	5	$	10	$	8	$	10

Noncurrent Regulatory Liabilities:
	Accumulated cost of removal
		of utility plant	$	673	$	651	$	294	$	286	$	379	$	365
	Coal contracts (a)			151		180		66		78		85		102
	Power purchase agreement - OVEC (a)			110		116		76		80		34		36
	Net deferred tax assets			35		39		28		31		7		8
	Defined benefit plans			10		9						10		9
	Other			8		8		3		3		5		5
Total noncurrent regulatory liabilities			$	987	$	1,003	$	467	$	478	$	520	$	525

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

Regulatory Matters

Kentucky Activities (PPL, LKE, LG&E and KU)

CPCN Filing

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. In May 2012, the KPSC issued an order approving the request to build the NGCC. LG&E will own a 22% undivided interest and KU will own a 78% undivided interest in the new NGCC. A formal request for recovery of the costs associated with the NGCC construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. See Note 8 for additional information.

In conjunction with this construction and to meet new, stricter EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant, one coal-fired generating unit at KU's Tyrone plant and two coal-fired generating units at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.

The CPCN application also requested approval to purchase the Bluegrass CTs. The May 2012 KPSC approval included authority to complete the Bluegrass CT acquisition. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC. LG&E and KU are currently assessing the impact of the asset purchase agreement termination and potential future generation capacity options. See Note 8 for additional information.

Kentucky Acquisition Commitments

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect, currently expected to be 2013. Therefore, due to the timing of the current rate case in Kentucky, no further ASSD filings are expected.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. The proposed base rate increases would result in electric rate increases of 6.9% at LG&E and 6.5% at KU and a gas rate increase of 7.0% at LG&E and would be effective in January 2013. LG&E's and KU's applications include requests for authorized returns-on-equity at LG&E and KU of 11% each. In November 2012, the KPSC issued an order for a settlement conference to begin on November 13, 2012. A hearing on the original application and subsequent testimony is scheduled to begin on November 27, 2012. LG&E and KU cannot predict the outcome of these proceedings, including the possibility of any agreed stipulations or settlement, which would remain subject to KPSC approval. A final order may be issued in December 2012 or January 2013.

Independent Transmission Operators

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

Storm Costs (PPL, LKE and LG&E)

In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011, requesting approval of a regulatory asset recorded to defer, for future recovery, $7 million in incremental operation and maintenance expenses related to the storm restoration. An order was received in December 2011 granting the request, while the recovery of the regulatory asset will be determined within the current base rate case discussed above in “Rate Case Proceedings”.

Pennsylvania Activities

(PPL and PPL Electric)

PUC Investigation of Retail Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. In December 2011, the PUC issued a final order providing guidance to Electric Distribution Companies (EDCs) on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC is expected to issue a tentative implementation order in early November 2012, following which parties will have 30 days to provide comment. A final implementation order is expected to be issued in the first quarter of 2013. PPL and PPL Electric cannot predict the outcome of the investigation or its impact on their financial condition, or results of operations.

Legislation - Regulatory Procedures and Mechanisms

In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation authorizing the PUC to approve regulatory procedures and mechanisms to provide more timely recovery of a utility's costs. In the first quarter of 2012, the Governor signed an amended version of the legislation (Act 11 of 2012), which became effective April 14, 2012. The legislation authorizes the PUC to approve two specific ratemaking mechanisms -- a fully projected future test year and, subject to certain conditions, a distribution system improvements charge (DSIC). Such alternative ratemaking procedures and mechanisms 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 of 2012. In September 2012, PPL Electric filed its Long Term Infrastructure Improvement Plan (LTIIP) describing projects eligible for inclusion in the DSIC. In October 2012, several parties filed comments to the LTIIP but none of the comments requested evidentiary hearings on the LTIIP. A decision on the LTIIP is expected in January 2013. PPL Electric expects to file a petition requesting permission to establish a DSIC in January 2013, with rates proposed to be effective in April 2013.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. The proposed distribution rate increase would result in a 2.9% increase over PPL Electric's total rates at the time of the request. PPL Electric's application includes a request for an authorized return on equity of 11.25%. On October 19, 2012, the presiding Administrative Law Judge (ALJ) issued a decision recommending a rate increase of approximately $64 million, which represents an allowed return on equity of 9.74%. Exceptions to the ALJ's recommendation are due November 8, 2012. PPL Electric expects to file exceptions, together with certain other parties, to the ALJ's recommended decision. The PUC, which is expected to issue its order on the rate request in December 2012, can accept, reject or modify the ALJ's recommendation. PPL and PPL Electric cannot predict the outcome of this proceeding.

ACT 129

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

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to reduce overall electricity consumption by 1.0% by May 2011 and 3.0% by May 2013, and reduce peak demand by 4.5% for the 100 hours of highest demand by May 2013 (which is determined by actual demand reduction during the June 2012 through September 2012 period). EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. The PUC has confirmed that PPL Electric has met the 2011 requirement.

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 March 2012, the PUC began the process of designing Phase II of the EE&C program. 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 consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish any demand reduction targets for the Phase II program. In August 2012 PPL Electric filed a Petition for Reconsideration of the PUC's Order, which the PUC denied. In August 2012, PPL Electric also filed a Petition for an Evidentiary Hearing regarding its consumption reduction target. The PUC assigned the petition to an ALJ. A hearing on the petition was held on October 18, 2012. The ALJ will certify the record of the hearing to the PUC for a decision. EDCs must file Phase II plans with the PUC by November 15, 2012. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings.

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

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

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. The PUC assigned PPL Electric's plan to an ALJ. Hearings were held in September 2012 and a recommended decision is expected in the fourth quarter of 2012. The PUC is expected to rule on the plan in early 2013.

Storm Costs

PPL Electric experienced several PUC-reportable storms during the three and nine months ended September 30, 2011 resulting in total restoration costs of $34 million and $59 million, of which $23 million and $39 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms exceeded policy limits. Probable recoveries on insurance claims of $26.5 million were recorded at September 30, 2011, of which $7 million and $16 million were recorded during the three and nine months ended September 30, 2011 in "Other operation and maintenance" on the Statement of Income, with the remainder recorded in PP&E on the Balance Sheet. 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. In the recommended decision in the distribution rate proceeding discussed above in "Pennsylvania Activities - Rate Case Proceeding," the presiding ALJ recommended that PPL Electric be allowed to recover deferred storm costs of approximately $27 million over a five-year period. The PUC, which is expected to issue its order in December 2012, can accept, reject or modify the ALJ's recommendation. New rates will become effective on January 1, 2013. PPL and PPL Electric cannot predict the outcome of this proceeding. In 2012, PPL Electric increased the deductible under its insurance policy to $15.75 million and, therefore, would only request insurance recovery of reportable storm costs exceeding that amount. During the three and nine months ended September 30, 2012, PPL Electric incurred $13 million in restoration costs, of which $9 million was recorded in "Other operation and maintenance" on the Statement of Income.

In late October 2012, PPL Electric experienced widespread significant damage to its transmission and distribution network from Hurricane Sandy. The total costs associated with the restoration efforts are still being finalized but are estimated to be in excess of $60 million. PPL Electric has insurance coverage that could cover a portion of the costs incurred from Hurricane Sandy. PPL Electric will have the ability to file a request with the PUC for permission to defer for future recovery certain of the costs incurred to repair the distribution network in excess of the insurance coverage. Costs incurred to repair the transmission network are recoverable through the FERC Formula Rate mechanism which is updated annually.

Transmission Service Charge Adjustment (PPL Electric)

During the three and nine months ended September 30, 2011, PPL Electric recorded a $7 million ($4 million after-tax) charge to "Retail electric" revenue on the Statement of Income to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC. The impact of this charge was not material to any previously reported financial statements and was not material to the financial statements for the full year of 2011.

Federal Matters (PPL and PPL Electric)

FERC Formula Rates

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.

In May 2010, PPL Electric initiated its formula rate 2010 Annual Update. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.

In May 2011, PPL Electric initiated its formula rate 2011 Annual Update. In October 2011, the group of municipal customers filed a preliminary challenge to the update and, in December 2011, filed a formal challenge. In January 2012, PPL Electric filed a response to that formal challenge. In September 2012, the FERC issued an order setting for evidentiary hearings a number of issues raised in the 2010 formal challenge and a number of issues raised in the 2011 formal challenge. The FERC held the hearings in abeyance for settlement judge proceedings and assigned a settlement judge. PPL Electric filed a request for rehearing of the September 2012 order in late October 2012. An initial settlement meeting will be scheduled in November 2012.

In May 2012, PPL Electric initiated its formula rate 2012 Annual Update which currently is in the 180-day review and challenge period. In October 2012, the group of municipal customers filed a preliminary challenge to the 2012 Annual Update. PPL Electric will meet with representatives of the customers in an attempt to resolve the challenge. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of approximately $50 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheets at September 30, 2012 and December 31, 2011. In May 2012, the FERC issued an order approving PPL Electric's request effective June 1, 2012.

U. K. Activities (PPL)

Ofgem Review of Line Loss Calculation

WPD has a $172 million liability recorded at September 30, 2012 compared with $170 million at December 31, 2011, calculated in accordance with Ofgem's accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013 together with a proposal to remove the line loss incentive/penalty for DPCR5. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 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, subject to approval by the European Commission of final technical standards, is expected to become effective in January 2013. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.