PPL Energy Supply enters into long-term energy and energy related contracts which include commitments to purchase:

(a) PPL Energy Supply enters into long-term purchase contracts to supply the coal requirements for its coal-fired generation facilities. As a result of lower electricity and natural gas prices, coal unit utilization has decreased. To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million during 2012 to reduce its 2012 and 2013 contracted coal deliveries. These charges were recorded to "Fuel" on the Statement of Income.

LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's gas supply operations. These contracts include the following commitments:

LG&E and KU have a power purchase agreement with OVEC expiring in June 2040. Pursuant to the OVEC power purchase contract, LG&E and KU are responsible for their pro-rata share of certain obligations of OVEC under defined circumstances. These potential liabilities include unpaid OVEC indebtedness as well as shortfall amounts in certain excess decommissioning costs and other post-employment and post-retirement benefit costs other than pension. LKE's proportionate share of OVEC's outstanding debt was $135 million at December 31, 2012, consisting of LG&E's share of $93 million and KU's share of $42 million. Future obligations for power purchases from OVEC are unconditional demand payments, comprised of annual minimum debt service payments, as well as contractually required reimbursement of plant operating, maintenance and other expenses as follows:

In addition, LG&E and KU had total energy purchases under the OVEC power purchase agreement for the periods ended as follows:

	Successor						Predecessor
					Two Months		Ten Months
	Year Ended		Year Ended		Ended		Ended
	December 31,		December 31,		December 31,		October 31,
	2012		2011		2010		2010

LG&E	$	20	$	22	$	4	$	17
KU		9		10		2		7
Total	$	29	$	32	$	6	$	24

In 2009, the PUC approved PPL Electric's procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted all of its planned competitive solicitations. The solicitations include a mix of long-term and short-term purchases, ranging from five months to ten years, to fulfill PPL Electric's obligation to provide for customer supply as a PLR. In May 2012, PPL Electric filed a plan with the PUC to purchase its electricity supply for default customers for the period June 2013 through May 2015. The PUC subsequently approved PPL Electric's plan on January 24, 2013. The approved plan proposes that PPL Electric procure this electricity through competitive solicitations conducted twice each plan year beginning in April 2013.

See Note 16 for information on the power supply agreements between PPL EnergyPlus and PPL Electric.

In connection with its marketing activities or hedging strategy for its power plants, PPL Energy Supply has entered into long-term power sales contracts that extend into 2019, excluding long-term renewable energy agreements that extend into 2038.

See Note 16 for information on the power supply agreements between PPL EnergyPlus and PPL Electric.

PPL Montana owns and operates 11 hydroelectric facilities and one storage reservoir licensed by the FERC under long-term licenses pursuant to the Federal Power Act. Pursuant to Section 8(e) of the Federal Power Act, the FERC approved the transfer from Montana Power to PPL Montana of all pertinent licenses in connection with the Montana Asset Purchase Agreement.

The Kerr Dam Project license (50-year term) was issued by the FERC jointly to Montana Power and the Confederated Salish and Kootenai Tribes of the Flathead Nation in 1985, and requires PPL Montana (as successor licensee to Montana Power) to hold and operate the project for at least 30 years (to 2015). Between 2015 and 2025, the tribes have the option to purchase, hold and operate the project for the remainder of the license term, which expires in 2035. While the tribes have indicated their intent to exercise the option at the earliest possible date, PPL Montana cannot predict if and when this option will be exercised. The license also requires PPL Montana to continue to implement a plan to mitigate the impact of the Kerr Dam on fish, wildlife and their habitats. Under this arrangement, PPL Montana has a remaining commitment to spend $6 million between 2013 and 2015, in addition to the annual rent it pays to the tribes.

PPL Montana entered into two Memoranda of Understanding (MOUs) with state, federal and private entities related to the issuance in 2000 of the FERC renewal license for the nine dams comprising the Missouri-Madison project. The MOUs are periodically updated and renewed and require PPL Montana to implement plans to mitigate the impact of its projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these arrangements, PPL Montana has a remaining commitment to spend $30 million between 2013 and 2040.

PPL and its subsidiaries are involved in legal proceedings, claims and litigation in the ordinary course of business. PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.

See footnote (l) to the table in "Guarantees and Other Assurances" below for information on an LKE indemnity relating to its former WKE lease, including related legal proceedings.

In November 2004, PPL Montana, Avista Corporation (Avista) and PacifiCorp commenced an action for declaratory judgment in Montana First Judicial District Court seeking a determination that no lease payments or other compensation for their hydroelectric facilities' use and occupancy of certain riverbeds in Montana can be collected by the State of Montana. This lawsuit followed dismissal on jurisdictional grounds of an earlier federal lawsuit seeking such compensation in the U.S. District Court of Montana. The federal lawsuit alleged that the beds of Montana's navigable rivers became state-owned trust property upon Montana's admission to statehood, and that the use of them should, under a 1931 regulatory scheme enacted after all but one of the hydroelectric facilities in question were constructed, trigger lease payments for use of land beneath. In July 2006, the Montana state court approved a stipulation by the State of Montana that it was not seeking compensation for the period prior to PPL Montana's December 1999 acquisition of the hydroelectric facilities.

Following a number of adverse trial court rulings, in 2007 Pacificorp and Avista each entered into settlement agreements with the State of Montana providing, in pertinent part, that each company would make prospective lease payments for use of the State's navigable riverbeds (subject to certain future adjustments), resolving the State's claims for past and future compensation.

Following an October 2007 trial of this matter on damages, in June 2008, the Montana District Court awarded the State retroactive compensation of approximately $35 million for the 2000-2006 period and approximately $6 million for 2007 compensation. Those unpaid amounts accrue interest at 10% per year. The Montana District Court also deferred determination of compensation for 2008 and future years to the Montana State Land Board. In October 2008, PPL Montana appealed the decision to the Montana Supreme Court, requesting a stay of judgment and a stay of the Land Board's authority to assess compensation for 2008 and future periods.

In March 2010, the Montana Supreme Court substantially affirmed the June 2008 Montana District Court decision. As a result, in the first quarter of 2010, PPL Montana recorded a pre-tax charge of $56 million ($34 million after tax), representing estimated rental compensation for the first quarter of 2010 and prior years, including interest. Rental compensation was estimated for periods subsequent to 2007. The portion of the pre-tax charge that related to prior years totaled $54 million ($32 million after tax). The pre-tax charge recorded on the Statement of Income was $49 million in "Other operation and maintenance" and $7 million in "Interest Expense."

In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition, and in February 2012 issued a decision overturning the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million ($53 million after-tax) which had been recorded prior to the U.S. Supreme Court decision. The amount reversed was recorded on the Statement of Income as a $75 million credit to "Other operation and maintenance" and a $14 million credit to "Interest Expense." PPL Montana believes the U.S. Supreme Court decision resolves certain questions of liability in this case in favor of PPL Montana and leaves open for reconsideration by Montana courts, consistent with the findings of the U.S. Supreme Court, certain other questions. In April 2012, the case was returned by the Montana Supreme Court to the Montana First Judicial District Court. Further proceedings have not yet been scheduled by the District Court. PPL Montana has concluded it is no longer probable, but it remains reasonably possible, that a loss has been incurred. While unable to estimate a range of loss, PPL Montana believes that any such amount would not be material.

In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure. This contract was accounted for as NPNS by PPL EnergyPlus.

The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices. Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract and made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT trustee and PPL EnergyPlus to terminate the SMGT Contract. As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell to other customers the electricity previously contracted to SMGT.

PPL EnergyPlus' receivable under the SMGT Contract, representing non-performance by SMGT prior to termination of the SMGT Contract, totaled approximately $21 million at December 31, 2012, which has been fully reserved.

In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim, including the above receivable, is approximately $375 million, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.

PPL Energy Supply cannot predict any amount that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.

In July 2012, PPL Montana received a Notice of Intent to Sue for violations of the Clean Air Act at Colstrip Steam Electric Station (Notice) from counsel on behalf of the Sierra Club and the MEIC. An Amended Notice was received on September 4, 2012, and a Second Amended Notice was received in October 2012. A Supplemental Notice was received in December 2012. The Notice, Amended Notice, Second Amended Notice, and Supplemental Notice (the Notices) were all addressed to the Owner or Managing Agent of Colstrip, and to the other Colstrip co-owners: Avista Corporation, Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Notice alleges certain violations of the Clean Air Act, including New Source Review, Title V and opacity requirements. The Amended Notice alleges additional opacity violations at Colstrip, and the Second Amended Notice alleges additional Title V violations. The Supplemental Notice includes additional New Source Review Claims. All four notices state that Sierra Club and MEIC will request a United States District Court to impose injunctive relief and civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require reimbursement of Sierra Club's and MEIC's costs of litigation and attorney's fees. Under the Clean Air Act, lawsuits cannot be filed until 60 days after the applicable notice date. PPL is evaluating the allegations set forth in the Notices and cannot at this time predict the outcome of this matter.

See Note 6 for information on regulatory matters related to utility rate regulation.

Enactment of Financial Reform Legislation (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The Dodd-Frank Act became effective in July 2010 and includes provisions that impose derivative transaction reporting requirements and require most over-the-counter derivative transactions to be executed through an exchange and to be centrally cleared. The Dodd-Frank Act also provides that the U.S. Commodity Futures Trading Commission (CFTC) may impose collateral and margin requirements for over-the-counter derivative transactions, as well as capital requirements for certain entity classifications. Final rules on major provisions in the Dodd-Frank Act are being established through rulemakings. The rulemakings are scheduled to become effective at different times beginning with the October 12, 2012 effective date of the definitional rule for the term "swap". In particular, the CFTC's Final Rule (Final Rule), defining key terms such as "swap dealer" and "major swap participant", took effect with the effectiveness of the swap definitional rule. The heightened thresholds and requirements for these entity classifications set forth in the Final Rule resulted in the Registrants currently being designated neither swap dealers nor major swap participants. The Dodd-Frank Act and its implementing regulations, however, will impose on the Registrants significant additional and costly recordkeeping and reporting requirements. Also, the Registrants could face significantly higher operating costs or may be required to post additional collateral if they or their counterparties are subject to capital or margin requirements as ultimately adopted in the implementing regulations of the Dodd-Frank Act. The Registrants will continue to evaluate the provisions of the Dodd-Frank Act and its implementing regulations. At this time, the Registrants cannot predict the impact that the law or its implementing regulations will have on their businesses or operations, or the markets in which they transact business, but could incur significant costs related to compliance with the Dodd-Frank Act.

In January 2011, New Jersey enacted a law that intervenes in the wholesale capacity market exclusively regulated by the FERC: S. No. 2381, 214th Leg. (N.J. 2011) (the Act). To create incentives for the development of new, in-state electric generation facilities, the Act implements a "long-term capacity agreement pilot program (LCAPP)." The Act requires New Jersey utilities to pay a guaranteed fixed price for wholesale capacity, imposed by the New Jersey Board of Public Utilities (BPU), to certain new generators participating in PJM, with the ultimate costs of that guarantee to be borne by New Jersey ratepayers. PPL believes the intent and effect of the LCAPP is to encourage the construction of new generation in New Jersey even when, under the FERC-approved PJM economic model, such new generation would not be economic. The Act could depress capacity prices in PJM in the short term, impacting PPL Energy Supply's revenues, and harm the long-term ability of the PJM capacity market to incent necessary generation investment throughout PJM. In February 2011, the PJM Power Providers Group (P3), an organization in which PPL is a member, filed a complaint before the FERC seeking changes in PJM's capacity market rules designed to ensure that subsidized generation, such as the generation that may result from the implementation of the LCAPP, will not be able to set capacity prices artificially low as a result of their exercise of buyer market power. In April 2011, the FERC issued an order granting in part and denying in part P3's complaint and ordering changes in PJM's capacity rules consistent with a significant portion of P3's requested changes. Several parties have filed appeals of the FERC's order. PPL, PPL Energy Supply and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.

In addition, in February 2011, PPL, and several other generating companies and utilities filed a complaint in U.S. District Court in New Jersey challenging the Act on the grounds that it violates well-established principles under the Supremacy Clause and the Commerce Clause of the U.S. Constitution. In this action, the plaintiffs request declaratory and injunctive relief barring implementation of the Act by the Commissioners of the BPU. In October 2011, the court denied the BPU's motion to dismiss the proceeding. In September 2012, the U.S. District Court denied all summary judgment motions, and the litigation is continuing. Trial is scheduled to begin in March 2013. PPL, PPL Energy Supply and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.

In April 2012, the Maryland Public Service Commission (MD PSC) ordered three electric utilities in Maryland to enter into long-term contracts to support the construction of new electric generating facilities in Maryland, specifically a 661 MW natural gas-fired combined-cycle generating facility to be owned by CPV Maryland, LLC. PPL believes the intent and effect of the action by the MD PSC is to encourage the construction of new generation in Maryland even when, under the FERC-approved PJM economic model, such new generation would not be economic. The MD PSC action could depress capacity prices in PJM in the short term, impacting PPL Energy Supply's revenues, and harm the long-term ability of the PJM capacity market to encourage necessary generation investment throughout PJM.

In April 2012, PPL and several other generating companies filed a complaint in U.S. District Court in Maryland challenging the MD PSC order on the grounds that it violates well-established principles under the Supremacy and Commerce clauses of the U.S. Constitution. In this action, the plaintiffs request declaratory and injunctive relief barring implementation of the order by the Commissioners of the MD PSC. In August 2012, the court denied the MD PSC and CPV Maryland, LLC motions to dismiss the proceeding and the litigation is continuing. Trial is scheduled to begin in March 2013. PPL, PPL Energy Supply, and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.

Through its subsidiaries, PPL Energy Supply made spot market bilateral sales of power in the Pacific Northwest during the period from December 2000 through June 2001. Several parties subsequently claimed refunds at FERC as a result of these sales. In June 2003, the FERC terminated proceedings to consider whether to order refunds for spot market bilateral sales made in the Pacific Northwest, including sales made by PPL Montana, during the period December 2000 through June 2001. In August 2007, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC's decision and ordered the FERC to consider additional evidence. In October 2011, FERC initiated proceedings to consider additional evidence. At June 30, 2012, there were two remaining claims against PPL Energy Supply totaling $73 million. In July 2012, PPL Montana and the City of Tacoma, one of the parties claiming refunds at FERC, reached a settlement whereby PPL Montana would pay $75 thousand to resolve the City of Tacoma's $23 million claim, $9 million of which represents interest. The settlement does not resolve the remaining claim outstanding at December 31, 2012 of approximately $50 million.

Although PPL and its subsidiaries believe they have not engaged in any improper trading or marketing practices affecting the Pacific Northwest markets, PPL and PPL Energy Supply cannot predict the outcome of the above-described proceedings or whether any subsidiaries will be the subject of any additional governmental investigations or named in other lawsuits or refund proceedings. Consequently, PPL and PPL Energy Supply cannot estimate a range of reasonably possible losses, if any, related to this matter.

In 1998, the FERC authorized LG&E, KU and PPL EnergyPlus to make wholesale sales of electric power and related products at market-based rates. In those orders, the FERC directed LG&E, KU and PPL EnergyPlus, respectively, to file an updated market analysis within three years after the order, and every three years thereafter. Since then, periodic market-based rate filings with the FERC have been made by LG&E, KU, PPL EnergyPlus, PPL Electric, PPL Montana and most of PPL Generation's subsidiaries. These filings consisted of a Northwest market-based rate filing for PPL Montana and a Northeast market-based rate filing for most of the other PPL subsidiaries in PJM's region. In June 2011, FERC approved PPL's market-based rate update for the Eastern and Western regions. Also, in June 2011, PPL filed its market-based rate update for the Southeast region, including LG&E and KU in addition to PPL EnergyPlus. In June 2011, the FERC issued an order approving LG&E's and KU's request for a determination that they no longer be deemed to have market power in the BREC balancing area and removing restrictions on their market-based rate authority in such region.

Currently, a seller granted FERC market-based rate authority may enter into power contracts during an authorized time period. If the FERC determines that the market is not workably competitive or that the seller possesses market power or is not charging "just and reasonable" rates, it may institute prospective action, but any contracts entered into pursuant to the FERC's market-based rate authority remain in effect and are generally subject to a high standard of review before the FERC can order changes. Recent court decisions by the U.S. Court of Appeals for the Ninth Circuit have raised issues that may make it more difficult for the FERC to continue its program of promoting wholesale electricity competition through market-based rate authority. These court decisions permit retroactive refunds and a lower standard of review by the FERC for changing power contracts, and could have the effect of requiring the FERC in advance to review most, if not all, power contracts. In June 2008, the U.S. Supreme Court reversed one of the decisions of the U.S. Court of Appeals for the Ninth Circuit, thereby upholding the higher standard of review for modifying contracts. At this time, PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU cannot predict the impact of these court decisions on the FERC's future market-based rate authority program or on their businesses.

The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk power system. The FERC oversees this process and independently enforces the Reliability Standards.

The Reliability Standards have the force and effect of law and apply to certain users of the bulk power electricity system, including electric utility companies, generators and marketers. Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations.

LG&E, KU, PPL Electric and certain subsidiaries of PPL Energy Supply monitor their compliance with the Reliability Standards and continue to self-report potential violations of certain applicable reliability requirements and submit accompanying mitigation plans, as required. The resolution of a number of potential violations is pending. Any Regional Reliability Entity (including RFC or SERC) determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC.

In the course of implementing their programs to ensure compliance with the Reliability Standards by those PPL affiliates subject to the standards, certain other instances of potential non-compliance may be identified from time to time. The Registrants cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any, other than the amounts currently recorded.

In October 2012, the FERC issued a Notice of Proposed Rulemaking (NOPR) concerning Reliability Standards for Geomagnetic Disturbances. The FERC proposes to direct NERC to submit for approval Reliability Standards that address the impact of geomagnetic disturbances on the reliable operation of the bulk-power system, including one or more measures to protect against damage to the bulk-power system, such as the installation of equipment that blocks geomagnetically induced currents on implicated transformers. If the NOPR is adopted by the FERC, it is expected to require the Registrants either or both to make significant expenditures in new equipment or modifications to their facilities. The Registrants are unable to predict whether the NOPR will be adopted as proposed by the FERC or the amount of any expenditures that may be required as a result of the adoption of any Reliability Standards for geomagnetic disturbances.

In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. PPL Susquehanna recorded credits totaling $56 million to "Fuel" on the Statement of Income in 2011 to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. The amounts recorded through September 2011 cover costs incurred from 1998 through December 2010. PPL Susquehanna is eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that are incurred through December 31, 2013. In exchange, PPL Susquehanna has waived any claims against the United States government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna plan through December 31, 2013.

Due to the environmental issues discussed below or other environmental matters, it may be necessary for the Registrants to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies or courts. In addition, legal challenges to new environmental permits or rules add to the uncertainty of estimating the future cost impact of these permits and rules.

LG&E and KU are entitled to recover, through the ECR mechanism, certain costs of complying with the Clean Air Act as amended and those federal, state, or local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal in accordance with their approved compliance plans. Costs not covered by the ECR for LG&E and KU and all such costs for PPL Electric are subject to rate recovery before their respective state regulatory authorities, or the FERC, if applicable. Because PPL Electric does not own any generating plants, its exposure to environmental compliance costs is reduced. As PPL Energy Supply is not a rate regulated entity, it does not have any mechanism for seeking rate recovery of environmental compliance costs. PPL, PPL Electric, LKE, LG&E and KU can provide no assurances as to the ultimate outcome of future environmental or rate proceedings before regulatory authorities.

In July 2011, the EPA adopted the CSAPR, which was intended to finalize and rename the Clean Air Transport Rule (Transport Rule) proposed in August 2010. The CSAPR replaced the EPA's previous CAIR which was invalidated by the U.S. Court of Appeals for the District of Columbia Circuit (the Court) in July 2008. CAIR subsequently was effectively reinstated by the Court in December 2008, pending finalization of the Transport Rule. Like CAIR, CSAPR only applied to PPL's fossil-fueled generating plants located in Kentucky and Pennsylvania.

In December 2011, the Court stayed implementation of the CSAPR and left CAIR in effect pending a final decision on the validity of the rule. In August 2012, the Court issued a ruling invalidating CSAPR, remanding the rule to the EPA for further action, and leaving CAIR in place during the interim. A further revised rule is not expected from the EPA for at least two years.

The CSAPR was meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxides emissions. The CSAPR established new sulfur dioxide and nitrogen oxide emission allowance cap and trade programs that were more restrictive than previously under CAIR. The CSAPR provided for two-phased programs of sulfur dioxide and nitrogen oxide emissions reductions, with initial reductions in 2012 and more stringent reductions in 2014.

The Kentucky fossil-fueled generating plants can meet the CAIR sulfur dioxide emission requirements by utilizing sulfur dioxide allowances (including banked allowances). To meet nitrogen oxide standards, under the CAIR, the Kentucky companies will need to buy allowances and/or make operational changes. LG&E and KU do not currently anticipate that the costs of meeting these reinstated CAIR requirements or standards will be significant.

PPL Energy Supply's Pennsylvania fossil-fueled generating plants can meet the CAIR sulfur dioxide emission requirements with the existing scrubbers that were placed in service in 2008 and 2009. To meet nitrogen oxide standards, under the CAIR, PPL Energy Supply will need to buy allowances and/or make operational changes, the costs of which are not anticipated to be significant.

In addition to the reductions in sulfur dioxide and nitrogen oxide emissions required under the CAIR for its Pennsylvania and Kentucky plants, PPL's fossil-fueled generating plants, including those in Montana, may face further reductions in sulfur dioxide and nitrogen oxide emissions as a result of more stringent national ambient air quality standards for ozone, nitrogen oxide, sulfur dioxide and/or fine particulates.

In 2010, the EPA finalized a new one-hour standard for sulfur dioxide, and states are required to identify areas that meet those standards and areas that are in non-attainment. For non-attainment areas, states are required to develop plans by 2014 to achieve attainment by 2017. For areas that are in attainment or that are unclassifiable, states are required to develop maintenance plans by mid-2013 that demonstrate continued attainment. In December 2012, the EPA issued final rules that strengthen the particulate standards. Under the final rule, states and the EPA have until the end of 2014 to identify initial non-attainment areas, and states have until 2020 to achieve attainment status for those areas. States can request an extension to 2025 to comply with the rule. Until particulate matter and sulfur dioxide maintenance and compliance plans are developed, PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict which of their facilities may be located in a non-attainment area and what measures would be required to achieve attainment status.

PPL, PPL Energy Supply, LKE, LG&E and KU anticipate that some of the measures required for compliance with the CAIR, the MATS, or the Regional Haze requirements, such as upgraded or new sulfur dioxide scrubbers at some of their plants and, in the case of LG&E and KU, the previously announced retirement of coal-fired generating units at the Cane Run, Green River and Tyrone plants, will help to achieve compliance with the new one-hour sulfur dioxide standard. If additional reductions were to be required, the financial impact could be significant.

In May 2011, the EPA published a proposed regulation providing for stringent reductions of mercury and other hazardous air pollutants. In February 2012, the EPA published the final rule, known as the MATS, with an effective date of April 16, 2012. The rule is being challenged by industry groups and states. The EPA issued a proposed rule in November 2012 reconsidering limited aspects of its MATS and New Source Performance Standards (NSPS) to which PPL responded with comments.

The rule provides for a three-year compliance deadline with the potential for a one-year extension as provided under the statute. Based on their assessment of the need to install pollution control equipment to meet the provisions of the proposed rule, LG&E and KU filed requests with the KPSC for environmental cost recovery to facilitate moving forward with plans to install environmental controls including chemical additive and fabric-filter baghouses to remove certain hazardous air pollutants. Recovery of the cost of certain controls was granted by the KPSC in December 2011. See Note 6 for information on LG&E's and KU's anticipated retirement of certain coal-fired electric generating units in response to this and other environmental regulations. With the publication of the final MATS rule, LG&E and KU are currently assessing whether any revisions of their approved compliance plans will be necessary.

With respect to PPL Energy Supply's Pennsylvania plants, PPL Energy Supply believes that certain coal-fired plants may require installation of chemical additive systems, the cost of which is not expected to be significant. With respect to PPL Energy Supply's Montana plants, modifications to the current air pollution controls installed on Colstrip may be required, the cost of which is not expected to be significant. For the Corette plant, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place the plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with the MATS requirements. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods as higher priced sales contracts settle, adversely impacting projected cash flows. PPL Energy Supply, LG&E and KU are continuing to conduct in-depth reviews of the MATS, including the potential implications to scrubber wastewater discharges. See the discussion of effluent limitations guidelines and standards below.

In January 2012, the EPA proposed limited approval of the Pennsylvania regional haze State Implementation Plan (PA SIP). That proposal would essentially approve PPL's analysis that further particulate controls at PPL Energy Supply's Pennsylvania plants are not warranted. The limited approval does not address deficiencies of the state plan arising from the remand of the CAIR. Previously, the EPA had determined that implementation of the CAIR requirements would meet regional haze requirements.

In 2012, the EPA finalized a rule providing that implementation of the CSAPR would also meet the Best Available Retrofit Technology (BART) requirements for sulfur dioxide and nitrogen oxides. This rule also addresses the PA SIP deficiency arising from the CAIR remand. However, in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (Court) vacated and remanded the CSAPR back to the EPA for further rulemaking (as discussed above). In September 2012, several environmental groups filed a petition for review with the Court challenging the EPA's approval of the PA SIP. At this time, it is not known whether the EPA will reinstate its previous determination that CAIR satisfies the BART requirement or will require states to conduct source-specific BART studies.

In Montana, the EPA Region 8 developed the regional haze plan as the Montana Department of Environmental Quality declined to develop a BART state implementation plan at this time. PPL submitted to the EPA its analyses of the visibility impacts of sulfur dioxide, nitrogen oxides and particulate emissions for Colstrip Units 1 and 2 and Corette. PPL's analyses concluded that further reductions are not warranted, except that the EPA concurred with the installation of Separated Overfire Air (SOFA) and lime injection for Units 1 and 2. PPL has also submitted data and analyses of various air emission control options under the rules to reduce air emissions related to the non-BART-affected emission sources of Colstrip Units 3 and 4. The analyses show that any incremental reductions would not be cost-effective and that further analysis is not warranted.

In September 2012, the EPA issued its final Federal Implementation Plans (FIP) for the Montana regional haze rule. The final FIP indicated that no additional controls were required for Corette or Colstrip Units 3 and 4 but proposed tighter limits for Corette and Colstrip Units 1 and 2. PPL Energy Supply expects to meet these tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015. See "Mercury and Other Hazardous Air Pollutants" discussion above. Under the final FIP, Colstrip Units 1 and 2 will require additional controls, including the possible installation of an SNCR and other technology, to meet more stringent nitrogen oxide and sulfur dioxide limits. The cost of these potential additional controls, if required, could be significant. In November 2012, PPL filed a petition for review of the Montana Regional Haze FIP with the U.S. Court of Appeals for the Ninth Circuit. Environmental groups have also filed a petition for review. The two matters have been consolidated, and the parties have agreed to a briefing schedule.

LG&E and KU also submitted analyses of the visibility impacts of their Kentucky BART-eligible sources to the Kentucky Division for Air Quality (KDAQ). Only LG&E's Mill Creek plant was determined to have a significant regional haze impact. The KDAQ has submitted a regional haze SIP to the EPA which requires the Mill Creek plant to reduce its sulfuric acid mist emissions from Units 3 and 4, the costs of which are not expected to be significant. After approval of the Kentucky SIP by the EPA and revision of the Mill Creek plant's air permit under Title V, LG&E intends to install sorbent injection controls at the plant to reduce sulfuric acid mist emissions.

The EPA has continued its NSR enforcement efforts targeting coal-fired generating plants. The EPA has asserted that modification of these plants has increased their emissions and, consequently, that they are subject to stringent NSR requirements under the Clean Air Act. In April 2009, PPL received EPA information requests for its Montour and Brunner Island plants. The requests are similar to those that PPL received in the early 2000s for its Colstrip, Corette and Martins Creek plants. PPL and the EPA have exchanged certain information regarding this matter. In January 2009, PPL and other companies that own or operate the Keystone plant in Pennsylvania received a notice of violation from the EPA alleging that certain projects were undertaken without proper NSR compliance. In May and November 2012, PPL Montana received information requests from the EPA regarding projects undertaken during the Spring 2012 maintenance outage at Colstrip Unit 1. In September 2012, PPL Montana received an information request from the Montana Department of Environmental Quality regarding the Unit 1 and other projects. PPL and PPL Energy Supply cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.

In addition, in August 2007, LG&E received information requests for the Mill Creek and Trimble County plants, and KU received requests for the Ghent plant, but they have received no further communications from the EPA since providing their responses. PPL, LKE, LG&E and KU cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.

In March 2009, KU received a notice alleging that KU violated certain provisions of the Clean Air Act's rules governing NSR and prevention of significant deterioration by installing sulfur dioxide scrubbers and SCR controls at its Ghent plant without assessing potential increased sulfuric acid mist emissions. KU contends that the work in question, as pollution control projects, was exempt from the requirements cited by the EPA. In December 2009, the EPA issued an information request on this matter. In September 2012, the parties reached a tentative settlement addressing the Ghent NSR matter and a September 2007 notice of violation alleging opacity violations at the plant. A consent decree was lodged in the U.S. District Court for the Eastern District of Kentucky in December 2012. PPL, LKE and KU cannot predict the outcome of this matter until the consent decree is entered by the Court, but currently do not expect such outcome to result in costs in excess of amounts already accrued, which amounts are not material.

If PPL subsidiaries are found to have violated NSR regulations, PPL, PPL Energy Supply, LKE, LG&E and KU would, among other things, be required to meet permit limits reflecting Best Available Control Technology (BACT) for the emissions of any pollutant found to have significantly increased due to a major plant modification. The costs to meet such limits, including installation of technology at certain units, could be significant.

States and environmental groups also have provided notice of their intention to initiate enforcement actions and litigation alleging violations of the NSR regulations by coal-fired generating plants. See "Legal Matters" above for information on a notice of intent to sue received in July 2012 (and amended multiple times thereafter) by PPL Montana and other owners of Colstrip. PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict whether such actions will be brought against any of their other plants.

In January 2013, Earthjustice, on behalf of the Sierra Club and the MEIC filed an administrative appeal with the Board of Environmental Review, setting forth challenges to certain components of the Title V permits for Colstrip and Corette. These challenges include: 1) the regional haze requirements should have been included in the Title V permits for Corette and Colstrip; 2) the MATS requirements should have been included in the Title V permits for Corette and Colstrip; 3) the particulate monitoring methodology is inadequate at Corette and Colstrip; and 4) sulfur dioxide monitoring is inadequate at Corette. PPL Montana intends to participate in this proceeding and cannot predict its outcome.

On January 31, 2013, the Sierra Club and the MEIC alleged identical claims in their joint petition to the EPA, requesting that the EPA object to the MDEQ's issuance of Colstrip's and Corette's Title V permits. PPL Montana cannot predict the outcome of this parallel matter pending before the EPA.

The Sierra Club and other environmental groups petitioned the Kentucky Environmental and Public Protection Cabinet to overturn the air permit issued for the TC2 baseload generating unit, but the agency upheld the permit in an order issued in September 2007. In response to subsequent petitions by environmental groups, the EPA ordered certain non-material changes to the permit which were incorporated into a final revised permit issued by the KDAQ in January 2010. In March 2010, the environmental groups petitioned the EPA to object to the revised state permit. Until the EPA issues a final ruling on the pending petition and all available appeals are exhausted, PPL, LKE, LG&E and KU cannot predict the outcome of this matter or the potential impact on the capital costs of this project, if any.

There is concern nationally and internationally about global climate change and the possible contribution of GHG emissions including, most significantly, carbon dioxide, from the combustion of fossil fuels. This has resulted in increased demands for carbon dioxide emission reductions from investors, environmental organizations, government agencies and the international community. These demands and concerns have led to federal legislative proposals, actions at regional, state and local levels, litigation relating to GHG emissions and the EPA regulations on GHGs.

While climate change legislation was actively considered in 2009-2010, such legislation has not significantly progressed. Since that time, although the U.S. House of Representatives passed legislation attempting to bar the EPA from regulating GHG emissions under the existing authority of the Clean Air Act, the Senate never took up the legislation. The timing and elements of future federal legislation addressing GHG emission reductions are uncertain at this time.

As a result of the April 2007 U.S. Supreme Court decision that the EPA has authority under the Clean Air Act to regulate GHG emissions from new motor vehicles, in April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that apply beginning with 2012 model year vehicles. The EPA also clarified that this standard, beginning in 2011, authorized regulation of GHG emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act. As a result, any new sources or major modifications to existing GHG sources causing a net significant emissions increase requires the BACT permit limits for GHGs. The rules were challenged, and in June 2012, the U.S. Court of Appeals for the District of Columbia Circuit upheld the EPA's regulations. In December 2012, the Court denied petitions for rehearing pertaining to the Court's June 2012 opinion.

In addition, in April 2012, the EPA proposed NSPS for carbon dioxide emissions from new coal-fired generating units, combined-cycle natural gas units, and integrated gasification combined-cycle units. The proposal would require new coal plants to achieve the same stringent limitations on carbon dioxide emissions as the best performing new gas plants. There presently is no commercially available technology to allow new coal plants to achieve these limitations and, as a result, the EPA's proposal would effectively preclude future construction of new coal-fired generation. In December 2012, the U.S. Court of Appeals for the District of Columbia Circuit dismissed consolidated challenges to the NSPS holding that the proposed rule is not a final agency action. The EPA is expected to finalize the NSPS for new sources in early 2013.

At the regional level, ten northeastern states signed a Memorandum of Understanding (MOU) agreeing to establish a GHG emission cap-and-trade program, called the Regional Greenhouse Gas Initiative (RGGI). The program commenced in January 2009 and calls for stabilizing carbon dioxide emissions, at base levels established in 2005, from electric power plants with capacity greater than 25 MW. The MOU also provides for a 10% reduction, by 2019, in carbon dioxide emissions from base levels.

Pennsylvania has not stated an intention to join the RGGI, but enacted the Pennsylvania Climate Change Act of 2008 (PCCA). The PCCA established a Climate Change Advisory Committee to advise the PADEP on the development of a Climate Change Action Plan. In December 2009, the Advisory Committee finalized its Climate Change Action Report and identified specific actions that could result in reducing GHG emissions by 30% by 2020. Some of the proposed actions, such as a mandatory 5% efficiency improvement at power plants, could be technically unachievable. To date, there have been no regulatory or legislative actions taken to implement the recommendations of the report. In addition, legislation has been introduced that would, if enacted, accelerate solar supply requirements and restrict eligible solar projects to those located in Pennsylvania. PPL and PPL Energy Supply cannot predict at this time whether this legislation will be enacted.

Eleven western states and certain Canadian provinces established the Western Climate Initiative (WCI) in 2003. The WCI established a goal of reducing carbon dioxide emissions by 15% below 2005 levels by 2020 and developed GHG emission allocations, offsets, and reporting recommendations. Montana was once a partner in the WCI, but by 2011 withdrew, along with several other western states.

In November 2008, the Governor of Kentucky issued a comprehensive energy plan including non-binding targets aimed at promoting improved energy efficiency, development of alternative energy, development of carbon capture and sequestration projects, and other actions to reduce GHG emissions. In December 2009, the Kentucky Climate Action Plan Council was established to develop an action plan addressing potential GHG reductions and related measures. To date, the state has not issued a final plan. The impact of any such plan is not now determinable, but the costs to comply with the plan could be significant.

A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting plants, and the law remains unsettled on these claims. In September 2009, the U.S. Court of Appeals for the Second Circuit in the case of AEP v. Connecticut reversed a federal district court's decision and ruled that several states and public interest groups, as well as the City of New York, could sue five electric utility companies under federal common law for allegedly causing a public nuisance as a result of their emissions of GHGs. In June 2011, the U.S. Supreme Court overturned the lower court and held that such federal common law claims were displaced by the Clean Air Act and regulatory actions of the EPA. In addition, in Comer v. Murphy Oil (Comer case), the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit) declined to overturn a district court ruling that plaintiffs did not have standing to pursue state common law claims against companies that emit GHGs. The complaint in the Comer case named the previous indirect parent of LKE as a defendant based upon emissions from the Kentucky plants. In January 2011, the Supreme Court denied a petition to reverse the Fifth Circuit's ruling. In May 2011, the plaintiffs in the Comer case filed a substantially similar complaint in federal district court in Mississippi against 87 companies, including KU and three other indirect subsidiaries of LKE, under a Mississippi statute that allows the re-filing of an action in certain circumstances. In March 2012, the Mississippi federal court granted defendants' motions to dismiss the state common law claims because plaintiffs had previously raised the same claims, plaintiffs lacked standing, plaintiffs' claims were displaced by the Clean Air Act, and other grounds. In April 2012, plaintiffs filed a notice of appeal in the Fifth Circuit. Additional litigation in federal and state courts over these issues is continuing. PPL, LKE and KU cannot predict the outcome of this litigation or estimate a range of reasonably possible losses, if any.

In 2012, PPL's power plants emitted approximately 70 million tons of carbon dioxide compared with 74 million tons in 2011. The totals reflect 35 million tons from PPL Generation and 35 million tons from LG&E's and KU's generating fleet. All tons are U.S. short tons (2,000 pounds/ton).

There has been interest in renewable energy legislation at both the state and federal levels. Federal legislation on renewable energy is not expected to be introduced this year. In Pennsylvania, bills were recently introduced in both the Senate and House amending the existing AEPS to accelerate the current solar generation obligation, but no action was taken before the end of the 2011-2012 legislative session. Future bills are expected calling for an increase in AEPS Tier 1 (renewable resources, such as wind and solar) obligations and to create a $25 million permanent funding program for solar. Bills have also been introduced in Montana to add hydropower as a qualified source to the renewable portfolio standard.

PPL, PPL Energy Supply, LKE, LG&E and KU believe there are financial, regulatory and logistical uncertainties related to the implementation of renewable energy mandates that will need to be resolved before the impact of such requirements on them can be estimated. Such uncertainties, among others, include the need to provide back-up supply to augment intermittent renewable generation, potential generation over-supply that could result from such renewable generation and back-up, impacts to PJM's capacity market and the need for substantial changes to transmission and distribution systems to accommodate renewable energy sources. These uncertainties are not directly addressed by proposed legislation. PPL and PPL Energy Supply cannot predict at this time the effect on their merchant plants' future competitive position, results of operation, cash flows and financial position of renewable energy mandates that may be adopted, although the costs to implement and comply with any such requirements could be significant.

In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs (as either hazardous or non-hazardous) under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes. The first approach would regulate CCRs as a hazardous waste under Subtitle C of the RCRA. This approach would materially increase costs and result in early retirements of many coal-fired plants, as it would require plants to retrofit their operations to comply with full hazardous waste requirements for the generation of CCRs and associated waste waters through generation, transportation and disposal. This would also have a negative impact on the beneficial use of CCRs and could eliminate existing markets for CCRs. The second approach would regulate CCRs as a solid (non-hazardous) waste under Subtitle D of the RCRA. This approach would mainly affect disposal and most significantly affect any wet disposal operations. Under this approach, many of the current markets for beneficial uses would not be affected. Currently, PPL expects that several of its plants in Kentucky and Montana could be significantly impacted by the requirements of Subtitle D of the RCRA, as these plants are using surface impoundments for management and disposal of CCRs.

The EPA has issued information requests on CCR management practices at numerous plants throughout the power industry as it considers whether or not to regulate CCRs as hazardous waste. PPL has provided information on CCR management practices at most of its plants in response to the EPA's requests. In addition, the EPA has conducted follow-up inspections to evaluate the structural stability of CCR management facilities at several PPL plants and PPL has implemented certain actions in response to recommendations from these inspections.

The EPA is continuing to evaluate the unprecedented number of comments it received on its June 2010 proposed regulations. In October 2011, the EPA issued a Notice of Data Availability (NODA) that requests comments on selected documents that the EPA received during the comment period for the proposed regulations. In addition, the U.S. House of Representatives in September 2012 approved a bill that was revised in the Senate to modify Subtitle D of the RCRA to provide for the proper management and disposal of CCRs and to preclude the EPA from regulating CCRs under Subtitle C of the RCRA. This revised bill is being considered in the Senate and the prospect for passage is uncertain.

In January 2012, a coalition of environmental groups filed a 60-day notice of intent to sue the EPA for failure to perform nondiscretionary duties under RCRA, which could require a deadline for the EPA to issue strict CCR regulations. In February 2012, two CCR recycling companies also issued a 60-day notice of intent to sue the EPA over its timeliness in issuing CCR regulations, but they requested that the EPA take a Subtitle D approach that would allow for continued recycling of CCRs. The coalition filed its lawsuit in April 2012 and litigation is continuing.

A final rulemaking is currently expected before the end of 2015. However, the timing of the final regulations could be accelerated by the outcome of the above litigation, which could require the EPA to issue its regulations sooner.

PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict at this time the final requirements of the EPA's CCR regulations or potential changes to the RCRA and what impact they would have on their facilities, but the financial impact could be material if regulated as a hazardous waste under Subtitle C and significant if regulated under Subtitle D.

In 2005, approximately 100 million gallons of water containing fly ash was released from a disposal basin at the Martins Creek plant used in connection with the operation of the plant's two 150 MW coal-fired generating units. This resulted in ash being deposited onto adjacent roadways and fields, and into a nearby creek and the Delaware River. PPL determined that the release was caused by a failure in the disposal basin's discharge structure. PPL conducted extensive clean-up and completed studies, in conjunction with a group of natural resource trustees and the Delaware River Basin Commission, evaluating the effects of the release on the river's sediment, water quality and ecosystem.

The PADEP filed a complaint in Pennsylvania Commonwealth Court against PPL Martins Creek and PPL Generation, alleging violations of various state laws and regulations and seeking penalties and injunctive relief. PPL and the PADEP have settled this matter. The settlement also required PPL to submit a report on the completed studies of possible natural resource damages. PPL subsequently submitted the assessment report to the Pennsylvania and New Jersey regulatory agencies and has continued discussing potential natural resource damages and mitigation options with the agencies. Subsequently, in August 2011 the PADEP submitted its National Resource Damage Assessment report to the court and to the interveners. In December 2011, the interveners commented on the PADEP report and in February 2012 the PADEP and PPL filed separate responses with the court. In March 2012, the court dismissed the interveners' case, but the interveners have appealed the dismissal to the Pennsylvania Supreme Court and a decision by the court is still pending.

Through December 31, 2012, PPL Energy Supply has spent $28 million for remediation and related costs and an insignificant remediation liability remains on the balance sheet. PPL and PPL Energy Supply cannot be certain of the outcome of the natural resource damage assessment or the associated costs, the outcome of any lawsuit that may be brought by citizens or businesses or the nature of any other regulatory or legal actions that may be initiated against PPL, PPL Energy Supply or their subsidiaries as a result of the disposal basin release. However, PPL and PPL Energy Supply currently do not expect such outcomes to result in significant losses above the amounts currently recorded.

Seepages or groundwater infiltration have been detected at active and retired wastewater basins and landfills at various PPL, PPL Energy Supply, LKE, LG&E and KU plants. PPL, PPL Energy Supply, LKE, LG&E and KU have completed or are completing assessments of seepages or groundwater infiltration at various facilities and have completed or are working with agencies to implement abatement measures, where required. A range of reasonably possible losses cannot currently be estimated.

In 2007, six plaintiffs filed a lawsuit in the Montana Sixteenth Judicial District Court against the Colstrip plant owners asserting property damage due to seepage from plant wastewater ponds. A settlement agreement was reached in July 2010 which would have resulted in a payment by PPL Montana, but certain of the plaintiffs later argued the settlement was not final. The Colstrip plant owners filed a motion to enforce the settlement and in October 2011 the court granted the motion and ordered the settlement to be completed in 60 days. The plaintiffs appealed the October 2011 order to the Montana Supreme Court, which affirmed the district court's order enforcing the settlement on December 31, 2012 and denied plaintiff's motion for rehearing on February 5, 2013. The parties have 60 days after the February 5, 2013 decision to complete the settlement. PPL Montana's share of the settlement is not expected to be significant.

In August 2012, PPL Montana entered into an Administrative Order on Consent (AOC) with the MDEQ which establishes a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at the Colstrip power plant. The AOC requires that within five years, PPL Montana provide financial assurance to the MDEQ for the costs associated with closure and future monitoring of the waste-water treatment facilities. PPL Montana cannot predict at this time if the actions required under the AOC will create the need to adjust the existing ARO related to these facilities.

In September 2012, Earthjustice filed an affidavit pursuant to Montana's Major Facility Siting Act (MFSA) that sought review of the AOC by Montana's Board of Environmental Review (BER), on behalf of the Sierra Club, the MEIC, and the National Wildlife Federation (NWF). In September 2012, PPL Montana filed an election with the BER to have this proceeding conducted in Montana state district court as contemplated by the MFSA. In October 2012, Earthjustice filed a petition for review of the AOC in the Montana state district court in Rosebud County.

In late October 2012, Earthjustice filed a second complaint against the MDEQ and PPL Montana in state district court in Lewis and Clark County on behalf of the Sierra Club, the MEIC and the NWF. This complaint alleges that the defendants have failed to take action under the MFSA and the Montana Water Quality Act to effectively monitor and correct issues of coal ash disposal and wastewater ponds at the Colstrip plant. The complaint seeks a declaration that the operations of the impoundments violate the statutes addressed above, requests a writ of mandamus directing the MDEQ to enforce the same, and seeks recovery of attorneys' fees and costs. PPL is vigorously defending these allegations, and PPL and PPL Energy Supply cannot predict the outcome of this matter.

The EPA finalized requirements in 2004 for new or modified cooling water intake structures. These requirements affect where generating plants are built, establish intake design standards and could lead to requirements for cooling towers at new and modified power plants. In 2009, however, the U.S. Supreme Court ruled that the EPA has discretion to use cost-benefit analysis in determining the best technology available for minimizing adverse environmental impact to aquatic organisms. The EPA published the proposed rule on new or modified cooling water intake structures in April 2011. The industry and PPL reviewed the proposed rule and submitted comments. The EPA has been evaluating comments and meeting with industry groups to discuss options. Two NODAs have been issued on the rule that indicate the EPA may be willing to amend the rule based on certain industry group comments, and the EPA's comment period on the NODAs has ended. The final rule is expected to be issued in 2013. The proposed rule contains two requirements to reduce impact to aquatic organisms. The first requires all existing facilities to meet standards for the reduction of mortality of aquatic organisms that become trapped against water intake screens regardless of the levels of mortality actually occurring or the cost of achieving the requirements. The second requirement is to determine and install the best technology available to reduce mortality of aquatic organisms that are pulled through the plant's cooling water system. A form of cost-benefit analysis is allowed for this second requirement. This process involves a site-specific evaluation based on nine factors, including impacts to energy delivery reliability and the remaining useful life of the plant. PPL, PPL Energy Supply, LKE, LG&E and KU cannot reasonably estimate a range of reasonably possible costs, if any, until a final rule is issued, the required studies have been completed, and each state in which they operate has decided how to implement the rule.

Effluent Limitations Guidelines and Standards (PPL, PPL Energy Supply, LKE, LG&E and KU)

In October 2009, the EPA released its Final Detailed Study of the Steam Electric Power Generating effluent limitations guidelines and standards. The EPA is expected to issue the final regulations in 2014. PPL, PPL Energy Supply, LKE, LG&E and KU expect the revised guidelines and standards to be more stringent than the current standards especially for sulfur dioxide scrubber wastewater. The guidelines are also expected to require dry ash handling, which could result in additional costs for technology retrofits for closure of wet basins. In the interim, states may impose more stringent limits on a case-by-case basis under existing authority as permits are renewed. Under the Clean Water Act, permits are subject to renewal every five years. PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible costs, but the costs could be significant.

In 2006, the EPA significantly decreased to 10 parts per billion (ppb) the drinking water standards for arsenic. In Pennsylvania, Montana and Kentucky, this arsenic standard has been incorporated into the states' water quality standards and could result in more stringent limits in NPDES permits for PPL's Pennsylvania, Montana and Kentucky plants. Subsequently, the EPA developed a draft risk assessment for arsenic that increases the cancer risk exposure by more than 20, which would lower the current standard from 10 ppb to 0.1 ppb. If the lower standard becomes effective, costly treatment would be required to attempt to meet the standard and, at this time, there is no assurance that it could be achieved. PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict the outcome of the draft risk assessment and what impact, if any, it would have on their plants, but the costs could be significant.

The EPA is reassessing its polychlorinated biphenyls (PCB) regulations under the Toxics Substance Control Act, which currently allow certain PCB articles to remain in use. In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking for changes to these regulations. This rulemaking could lead to a phase-out of all PCB-containing equipment. The EPA is planning to propose the revised regulations in late 2013. PCBs are found, in varying degrees, in all of the Registrants' operations. The Registrants cannot predict at this time the outcome of these proposed EPA regulations and what impact, if any, they would have on their facilities, but the costs could be significant.

A PPL Energy Supply subsidiary signed a Consent Order and Agreement (COA) with the PADEP in July 2008 under which it agreed, under certain conditions, to take further actions to minimize the possibility of fish kills at its Brunner Island plant. Fish are attracted to warm water in the power plant discharge channel, especially during cold weather. Debris at intake pumps can result in a unit trip or reduction in load, causing a sudden change in water temperature and fish mortality. A barrier has been constructed to prevent debris from entering the river water intake area at a cost that was not significant.

PPL Energy Supply's subsidiary has also investigated alternatives to exclude fish from the discharge channel, but the subsidiary and the PADEP have concluded that a barrier method to exclude fish is not workable. In June 2012, a new COA was signed that allows the subsidiary to study a change in a cooling tower operational method that may keep fish from entering the channel. Should this approach fail, the new COA requires a retrofit of impingement control technology at the intakes to the cooling towers, the cost of which could be significant.

In May 2010, the subsidiary received a draft NPDES permit (renewed) for the Brunner Island plant from the PADEP. This permit includes new water quality-based limits for the scrubber wastewater plant. Some of these limits may not be achievable with the existing treatment system. Several agencies and environmental groups commented on the draft permit, raising issues that must be resolved to obtain a final permit for the plant. PPL Energy Supply cannot predict the outcome of the final resolution of the permit issues at this time, or what impact, if any, they would have on this facility, but the costs could be significant.

In May 2010, the Kentucky Waterways Alliance and other environmental groups filed a petition with the Kentucky Energy and Environment Cabinet challenging the Kentucky Pollutant Discharge Elimination System permit issued in April 2010, which covers water discharges from the Trimble County plant. In November 2010, the Cabinet issued a final order upholding the permit. In December 2010, the environmental groups appealed the order to the Trimble Circuit Court, but the case was subsequently transferred to the Franklin Circuit Court. PPL, LKE, LG&E and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible losses, if any.

The EPA and the Army Corps of Engineers are working on a guidance document that will expand the federal government's interpretation of what constitutes "waters of the United States" subject to regulation under the Clean Water Act. This change has the potential to affect generation and delivery operations, with the most significant effect being the potential elimination of the existing regulatory exemption for plant waste water treatment systems. The costs that may be imposed on the Registrants as a result of any eventual expansion of this interpretation cannot reliably be estimated at this time but could be significant.

Superfund and Other Remediation (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

PPL Electric is potentially responsible for costs at several sites listed by the EPA under the federal Superfund program, including the Columbia Gas Plant site, the Metal Bank site and the Ward Transformer site. Clean-up actions have been or are being undertaken at all of these sites, the costs of which have not been significant to PPL Electric. However, should the EPA require different or additional measures in the future, or should PPL Electric's share of costs at multi-party sites increase substantially more than currently expected, the costs could be significant.

PPL Electric, LG&E and KU are remediating or have completed the remediation of several sites that were not addressed under a regulatory program such as Superfund, but for which PPL Electric, LG&E and KU may be liable for remediation. These include a number of former coal gas manufacturing plants in Pennsylvania and Kentucky previously owned or operated or currently owned by predecessors or affiliates of PPL Electric, LG&E and KU. There are additional sites, formerly owned or operated by PPL Electric, LG&E and KU predecessors or affiliates, for which PPL Electric, LG&E and KU lack information on current site conditions and are therefore unable to predict what, if any, potential liability they may have.

Depending on the outcome of investigations at sites where investigations have not begun or been completed or developments at sites for which PPL Electric, LG&E and KU currently lack information, the costs of remediation and other liabilities could be material. PPL, PPL Electric, LKE, LG&E and KU cannot estimate a range of reasonably possible losses, if any, related to these matters.

The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of coal gas manufacturing. As a result of the EPA's evaluation, individual states may establish stricter standards for water quality and soil cleanup. This could require several PPL subsidiaries to take more extensive assessment and remedial actions at former coal gas manufacturing plants. PPL, PPL Electric, LKE, LG&E and KU cannot estimate a range of reasonably possible losses, if any, related to these matters.

Under the Pennsylvania Clean Streams Law, subsidiaries of PPL Generation are obligated to remediate acid mine drainage at former mine sites and may be required to take additional steps to prevent potential acid mine drainage at previously capped refuse piles. One PPL Generation subsidiary is pumping mine water at two mine sites and treating water at one of these sites. Another PPL Generation subsidiary has installed a passive wetlands treatment system at a third site. At December 31, 2012, PPL Energy Supply had accrued a discounted liability of $26 million to cover the costs of pumping and treating groundwater at the two mine sites for 50 years and for operating and maintaining passive wetlands treatment at the third site. PPL Energy Supply discounted this liability based on risk-free rates at the time of the mine closures. The weighted-average rate used was 8.19%. Expected undiscounted payments are estimated at $3 million for 2013, $1 million for each of the years from 2014 through 2017, and $139 million for work after 2017.

From time to time, PPL Energy Supply, PPL Electric, LG&E and KU undertake remedial action in response to spills or other releases at various on-site and off-site locations, negotiate with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiate with property owners and other third parties alleging impacts from PPL's operations and undertake similar actions necessary to resolve environmental matters which arise in the course of normal operations. Based on analyses to date, resolution of these environmental matters is not expected to have a significant adverse impact on their operations.

Future cleanup or remediation work at sites currently under review, or at sites not currently identified, may result in significant additional costs for the Registrants.

WPD's distribution businesses are subject to environmental regulatory and statutory requirements. PPL believes that WPD has taken and continues to take measures to comply with the applicable laws and governmental regulations for the protection of the environment.

The U.K. Government has requested that utilities undertake projects to alleviate the impact of flooding on the U.K. utility infrastructure, including major electricity substations. WPD has agreed with the Ofgem to spend $45 million on flood prevention, which will be recovered through rates during the ten-year period commencing April 2010. WPD is currently liaising on site-specific proposals with local offices of a U.K. Government agency.

There are no other material legal or administrative proceedings pending against or related to WPD with respect to environmental matters.

PPL Susquehanna is a member of certain insurance programs that provide coverage for property damage to members' nuclear generating plants. Facilities at the Susquehanna plant are insured against property damage losses up to $2.75 billion under these programs. PPL Susquehanna is also a member of an insurance program that provides insurance coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.

Under the property and replacement power insurance programs, PPL Susquehanna could be assessed retroactive premiums in the event of the insurers' adverse loss experience. At December 31, 2012, this maximum assessment was $48 million.

In the event of a nuclear incident at the Susquehanna plant, PPL Susquehanna's public liability for claims resulting from such incident would be limited to $12.6 billion under provisions of The Price-Anderson Act as amended. PPL Susquehanna is protected against this liability by a combination of commercial insurance and an industry assessment program.

In the event of a nuclear incident at any of the reactors covered by The Price-Anderson Act as amended, PPL Susquehanna could be assessed up to $235 million per incident, payable at $35 million per year.

In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage.

PPL fully and unconditionally guarantees all of the debt securities of PPL Capital Funding.

The table below details guarantees provided as of December 31, 2012. The total recorded liability at December 31, 2012 and 2011 was $24 million and $14 million for PPL and $20 million and $11 million for LKE. The probability of expected payment/performance under each of these guarantees is remote except for "WPD guarantee of pension and other obligations of unconsolidated entities" and "Indemnification of lease termination and other divestitures." For reporting purposes, on a consolidated basis, all guarantees of PPL Energy Supply (other than the letters of credit), PPL Electric, LKE, LG&E and KU also apply to PPL, and all guarantees of LG&E and KU also apply to LKE.

		Exposure at			Expiration
		December 31, 2012 (a)			Date
PPL
Indemnifications related to the WPD Midlands acquisition				(b)
WPD indemnifications for entities in liquidation and sales of assets		$	11	(c)	2015
WPD guarantee of pension and other obligations of unconsolidated entities			91	(d)	2015

PPL Energy Supply
Letters of credit issued on behalf of affiliates			23	(e)	2013 - 2014
Retrospective premiums under nuclear insurance programs			48	(f)
Nuclear claims assessment under The Price-Anderson Act Amendments
	under The Energy Policy Act of 2005		235	(g)
Indemnifications for sales of assets			250	(h)	2025
Indemnification to operators of jointly owned facilities			6	(i)
Guarantee of a portion of a divested unconsolidated entity's debt			22	(j)	2018


PPL Electric
Guarantee of inventory value			21	(k)	2016

LKE
Indemnification of lease termination and other divestitures			301	(l)	2021 - 2023

LG&E and KU
LG&E and KU guarantee of shortfall related to OVEC				(m)

(a) Represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee.

(b) Prior to PPL's acquisition, WPD Midlands Holdings Limited had agreed to indemnify certain former directors of a Turkish entity in which WPD Midlands Holdings Limited previously owned an interest, for any liabilities that may arise as a result of an investigation by Turkish tax authorities, and PPL WEM has received a cross-indemnity from E.ON AG with respect to these indemnification obligations. Additionally, PPL subsidiaries agreed to provide indemnifications to subsidiaries of E.ON AG for certain liabilities relating to properties and assets owned by affiliates of E.ON AG that were transferred to WPD Midlands in connection with the acquisition. The maximum exposure and expiration of these indemnifications cannot be estimated because the maximum potential liability is not capped and the expiration date is not specified in the transaction documents.

(c) In connection with the liquidation of wholly owned subsidiaries that have been deconsolidated upon turning the entities over to the liquidators, certain affiliates of PPL Global have agreed to indemnify the liquidators, directors and/or the entities themselves for any liabilities or expenses arising during the liquidation process, including liabilities and expenses of the entities placed into liquidation. In some cases, the indemnifications are limited to a maximum amount that is based on distributions made from the subsidiary to its parent either prior or subsequent to being placed into liquidation. In other cases, the maximum amount of the indemnifications is not explicitly stated in the agreements. The indemnifications generally expire two to seven years subsequent to the date of dissolution of the entities. The exposure noted only includes those cases in which the agreements provide for a specific limit on the amount of the indemnification, and the expiration date was based on an estimate of the dissolution date of the entities.

In connection with their sales of various businesses, WPD and its affiliates have provided the purchasers with indemnifications that are standard for such transactions, including indemnifications for certain pre-existing liabilities and environmental and tax matters. In addition, in connection with certain of these sales, WPD and its affiliates have agreed to continue their obligations under existing third-party guarantees, either for a set period of time following the transactions or upon the condition that the purchasers make reasonable efforts to terminate the guarantees. Finally, WPD and its affiliates remain secondarily responsible for lease payments under certain leases that they have assigned to third parties.

(d) As a result of the privatization of the utility industry in the U.K., certain electric associations' roles and responsibilities were discontinued or modified. As a result, certain obligations, primarily pension-related, associated with these organizations have been guaranteed by the participating members. Costs are allocated to the members based on predetermined percentages as outlined in specific agreements. However, if a member becomes insolvent, costs can be reallocated to and are guaranteed by the remaining members. At December 31, 2012, WPD has recorded an estimated discounted liability based on its current allocated percentage of the total expected costs for which the expected payment/performance is probable. Neither the expiration date nor the maximum amount of potential payments for certain obligations is explicitly stated in the related agreements. Therefore, they have been estimated based on the types of obligations.

(e) Standby letter of credit arrangements under PPL Energy Supply's credit facilities for the purposes of protecting various third parties against nonperformance by PPL. This is not a guarantee by PPL on a consolidated basis.

(f) PPL Susquehanna is contingently obligated to pay this amount related to potential retrospective premiums that could be assessed under its nuclear insurance programs. See "Nuclear Insurance" above for additional information.

(g) This is the maximum amount PPL Susquehanna could be assessed for each incident at any of the nuclear reactors covered by this Act. See "Nuclear Insurance" above for additional information.

(h) PPL Energy Supply's maximum exposure with respect to certain indemnifications and the expiration of the indemnifications cannot be estimated because, in the case of certain indemnification provisions, the maximum potential liability is not capped by the transaction documents and the expiration date is based on the applicable statute of limitation. The exposure and expiration dates noted are only for those cases in which the agreements provide for specific limits. The indemnification provisions described below are in each case subject to certain customary limitations, including thresholds for allowable claims, caps on aggregate liability, and time limitations for claims arising out of breaches of most representations and warranties.

A subsidiary of PPL Energy Supply has agreed to provide indemnification to the purchaser of the Long Island generation business for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreement and for damages arising out of certain other matters, including liabilities relating to certain renewable energy facilities which were previously owned by one of the PPL subsidiaries sold in the transaction but which were unrelated to the Long Island generation business. The indemnification provisions for most representations and warranties expired in the third quarter of 2011.

A subsidiary of PPL Energy Supply has agreed to provide indemnification to the purchasers of the Maine hydroelectric facilities for damages arising out of any breach of the representations, warranties and covenants under the respective transaction agreements and for damages arising out of certain other matters, including liabilities of the PPL Energy Supply subsidiary relating to the pre-closing ownership or operation of those hydroelectric facilities. The indemnification provisions for most representations and warranties expired in the fourth quarter of 2012.

Subsidiaries of PPL Energy Supply have agreed to provide indemnification to the purchasers of certain non-core generation facilities sold in March 2011 for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreements and for damages arising out of certain other matters relating to the facilities that were the subject of the transaction, including certain reduced capacity payments (if any) at one of the facilities in the event specified PJM rule changes are proposed and become effective. The indemnification provisions for most representations and warranties expired in the first quarter of 2012.

(i) In December 2007, a subsidiary of PPL Energy Supply executed revised owners agreements for two jointly owned facilities, the Keystone and Conemaugh generating plants. The agreements require that in the event of any default by an owner, the other owners fund contributions for the operation of the generating plants, based upon their ownership percentages. The non-defaulting owners, who make up the defaulting owner's obligations, are entitled to the generation entitlement of the defaulting owner, based upon their ownership percentage. The exposure shown reflects the PPL Energy Supply subsidiary's share of the maximum obligation. The agreements do not have an expiration date.

(j) A PPL Energy Supply subsidiary owned a one-third equity interest in Safe Harbor Water Power Corporation (Safe Harbor) that was sold in March 2011. Beginning in 2008, PPL Energy Supply guaranteed one-third of any amounts payable with respect to certain senior notes issued by Safe Harbor. Under the terms of the sale agreement, PPL Energy Supply continues to guarantee the portion of Safe Harbor's debt, but received a cross-indemnity from the purchaser, secured by a lien on the purchaser's stock of Safe Harbor, in the event PPL Energy Supply is required to make a payment under the guarantee. The exposure noted reflects principal only. See Note 9 for additional information on the sale of this interest.

(k) PPL Electric entered into a contract with a third party logistics firm that provides inventory procurement and fulfillment services. Under the contract, the logistics firm has title to the inventory purchased for PPL Electric's use. Upon termination of the contract, PPL Electric has guaranteed to purchase any remaining inventory that has not been used or sold by the logistics firm at the weighted-average cost at which the logistics firm purchased the inventory, thus protecting the logistics firm from reductions in the fair value of the inventory.

(l) LKE provides certain indemnifications, the most significant of which relate to the termination of the WKE lease in July 2009. See Note 9 for additional information. These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations. The most comprehensive of these guarantees is the LKE guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement. This guarantee has a term of 12 years ending July 2021, and a cumulative maximum exposure of $200 million. Certain items such as government fines and penalties fall outside the cumulative cap. LKE has contested the applicability of the indemnification requirement relating to one matter presented by a counterparty under this guarantee. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. In May 2012, LKE's indemnitee received an arbitration panel's decision affecting this matter, which granted LKE's indemnitee certain rights of first refusal to purchase excess power at a market-based price rather than at an absolute fixed price. In January 2013, LKE's indemnitee commenced a proceeding in the Kentucky Court of Appeals appealing a December 2012 order of the Henderson Circuit Court confirming the arbitration award. LKE believes its indemnification obligations in this matter remain subject to various uncertainties, including the potential for additional legal challenges regarding the arbitration decision as well as future prices, availability and demand for the subject excess power. LKE continues to evaluate various legal and commercial options with respect to this indemnification matter. The ultimate outcomes of the WKE termination-related indemnifications cannot be predicted at this time. Additionally, LKE has indemnified various third parties related to historical obligations for other divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum exposures range from being capped at the sale price to no specified maximum; however, LKE is not aware of formal claims under such indemnities made by any party at this time. LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. In the second quarter of 2012, LKE adjusted its estimated liability for certain of these indemnifications by $9 million ($5 million after-tax), which is reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income. The adjustment was recorded in the Kentucky Regulated segment for PPL. LKE cannot predict the ultimate outcomes of such indemnification circumstances, but does not currently expect such outcomes to result in significant losses above the amounts recorded.

(m) As described in the "Energy Purchase Commitments" above, pursuant to the OVEC power purchase contract, expiring in June 2040, LG&E and KU are obligated to pay a demand charge which includes, among other charges, debt service and amortization toward principal retirement, decommissioning costs, post-retirement and post-employment benefits costs (other than pensions), and reimbursement of plant operating, maintenance and other expenses. The demand charge is expected to cover LG&E's and KU's shares of the cost of the listed items over the term of the contract. However, in the event there is a shortfall in covering these costs, LG&E and KU are obligated to pay their share of the excess debt service, post-retirement and decommissioning costs. The maximum exposure and the expiration date of these potential obligations are not presently determinable.

The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business. These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration. The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is remote.

PPL, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage. The coverage requires a maximum $4 million deductible per occurrence and provides maximum aggregate coverage of $200 million. This insurance may be applicable to obligations under certain of these contractual arrangements.