PPL Energy Supply enters into long-term purchase contracts to supply the fuel requirements and other costs of production for generation facilities. These contracts include commitments to purchase coal, emission allowances, limestone, natural gas, oil and nuclear fuel. These long-term contracts extend through 2023, with the exception of a limestone contract that extends through 2030. PPL Energy Supply also enters into long-term contracts for the storage and transportation of natural gas. The long-term natural gas storage contracts extend through 2015, and the long-term natural gas transportation contracts extend through 2032. PPL Energy Supply has entered into long-term contracts to purchase power that extend through 2017, with the exception of long-term power purchase agreements for the full output of two wind farms that extend through 2027. Additionally, PPL Energy Supply has entered into REC contracts that extend through 2038.

In 2008, PPL EnergyPlus acquired the rights to an existing long-term tolling agreement associated with the capacity and energy of Ironwood. Under the agreement, PPL EnergyPlus has control over the plant's dispatch into the electricity grid and supplies the natural gas necessary to operate the plant. The tolling agreement extends through 2021. See Note 11 for additional information.

LG&E and KU have a power purchase agreement with OVEC, extended in February 2011 to June 2040. FERC approval of the extension was received in May 2011, followed by KPSC and VSCC approvals in August 2011. 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 $117 million at December 31, 2011, consisting of LG&E's share of $81 million and KU's share of $36 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:

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. The coal contracts extend through 2016 and the natural gas contracts extend through 2013. LG&E and KU also enter into contracts for other coal related consumables, coal transportation and fleeting services, which expire at different time periods through 2018. LG&E and KU also have transportation contracts for natural gas that extend through 2018.

In 2009, the PUC approved PPL Electric's PLR energy procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted ten of its 14 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.

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 through 2024, excluding long-term retail sales agreements for the full output from solar generators that extend through 2036.

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 jointly issued by the FERC 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. 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 $8 million between 2012 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 $32 million between 2012 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.

In June 2006, LG&E and KU, as well as the Indiana Municipal Power Agency and Illinois Municipal Electric Agency (collectively, TC2 Owners), entered into a construction contract regarding the TC2 project. The contract is generally in the form of a turnkey agreement for the design, engineering, procurement, construction, commissioning, testing and delivery of the project, according to designated specifications, terms and conditions. The contract price and its components are subject to a number of potential adjustments which may serve to increase or decrease the ultimate construction price. During 2009 and 2010, the TC2 Owners received several contractual notices from the TC2 construction contractor asserting historical force majeure and excusable event claims for a number of adjustments to the contract price, construction schedule, commercial operations date, liquidated damages or other relevant provisions. In September 2010, the TC2 Owners and the construction contractor agreed to a settlement to resolve the force majeure and excusable event claims occurring through July 2010, under the TC2 construction contract, which settlement provided for a limited, negotiated extension of the contractual commercial operations date and/or relief from liquidated damage calculations. With limited exceptions, the TC2 Owners took care, custody and control of TC2 in January 2011. Pursuant to certain amendments to the construction agreement, the contractor will complete modifications to the combustion system prior to certain dates to allow operation of TC2 on all specified fuels categories. The provisions of the construction agreement relating to liquidated damages were also amended. In September 2011, the TC2 Owners and the construction contractor entered into a further amendment to the construction agreement settling, among other matters, certain historical change order, labor rate and prior liquidated damages amounts. The remaining issues are still under discussion with the contractor. PPL, LKE, LG&E and KU cannot currently predict the outcome of this matter or the potential impact on the capital costs of this project.

Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel, but there is no definitive date by which a repository will be operational. As a result, it was necessary to expand Susquehanna's on-site spent fuel storage capacity. To support this expansion, PPL Susquehanna contracted for the design and construction of a spent fuel storage facility employing dry cask fuel storage technology. The facility is modular, so that additional storage capacity can be added as needed. The facility began receiving spent nuclear fuel in 1999. PPL Susquehanna estimates that there is sufficient storage capacity in the spent nuclear fuel pools and the on-site dry cask storage facility at Susquehanna to accommodate spent fuel discharged through approximately 2017 under current operating conditions. If necessary, on-site dry cask storage capability can be expanded, assuming appropriate regulatory approvals are obtained, such that, together, the spent fuel pools and the expanded dry fuel storage facilities will accommodate all of the spent fuel expected to be discharged through the current licensed life of each unit, 2042 for Unit 1 and 2044 for Unit 2.

In 1996, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) ruled that the Nuclear Waste Policy Act imposed on the DOE an unconditional obligation to begin accepting spent nuclear fuel on or before January 31, 1998. In 1997, the D.C. Circuit Court ruled that the contracts between the utilities and the DOE provide a potentially adequate remedy if the DOE failed to begin accepting spent nuclear fuel by January 31, 1998. The DOE did not, in fact, begin to accept spent nuclear fuel by that date. The DOE continues to contest claims that its breach of contract resulted in recoverable damages. In January 2004, PPL Susquehanna filed suit in the U.S. Court of Federal Claims for unspecified damages suffered as a result of the DOE's breach of its contract to accept and dispose of spent nuclear fuel. In May 2011, the parties entered into a settlement agreement which resolved all claims of PPL Susquehanna through December 2013. Under the settlement agreement, PPL Susquehanna received $50 million for its share of claims to recover costs to store spent nuclear fuel at the Susquehanna plant through September 30, 2009, and recognized a credit to "Fuel" expense in the second quarter of 2011. PPL Susquehanna also will be eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that are incurred thereafter through the December 31, 2013 termination date of the settlement agreement. 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 plant through December 31, 2013.

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 continued to 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 2009, PPL Montana adjusted its previously recorded accrual by $8 million, $5 million after tax. Of this total, $5 million, $3 million after tax, related to prior 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 charge of $56 million ($34 million after tax or $0.08 per share, basic and diluted, for PPL), 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 charge recorded on the Statement of Income was $49 million in "Other operation and maintenance" and $7 million in "Interest Expense." PPL Montana continued to accrue interest expense for the prior years and rent expense for the subsequent years.

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. Oral argument was held in December 2011 and on February 22, 2012, the U.S. Supreme Court 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, PPL Montana reversed its total loss accrual of $89 million ($53 million after-tax or $0.09 per share, basic and diluted for PPL), which had been recorded prior to the U.S. Supreme Court decision. The amount reversed was recorded on the Statements 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. The State of Montana has 30 days from February 22, 2012 to petition the U.S. Supreme Court for a rehearing. 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.

Bankruptcy of Southern Montana Electric Generation and Transmission Cooperative, Inc.

On October 21, 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 in Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest customer.

The SMGT Contract provides for fixed volume purchases on a monthly basis at established prices. A trustee has been appointed for SMGT's estate in the bankruptcy proceeding, and PPL EnergyPlus has been involved in preliminary discussions with the trustee concerning possible modifications to the SMGT Contract as part of the bankruptcy reorganization. Pursuant to a court order and subsequent stipulations entered into by SMGT 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 has made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. During January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In addition, the trustee requested PPL EnergyPlus to leave the SMGT Contract in place to permit SMGT to purchase electricity in the event its requirements were not met by third-party providers from whom the trustee intends to purchase power on behalf of SMGT, at prices more favorable than under the SMGT Contract, for future periods. PPL EnergyPlus is evaluating the trustee's request.

PPL EnergyPlus' damage claim under the SMGT Contract totaled approximately $11 million at December 31, 2011, all of which has been fully reserved. No assurance can be given as to the collectability of these damages.

At the present time, PPL cannot predict whether SMGT will be successful in its attempts to reorganize its business under Chapter 11 of the U.S. Bankruptcy Code or the extent to which the SMGT Contract may be modified as part of a successful Chapter 11 reorganization and, in either case, PPL cannot presently predict the extent to which it will be able to market to third parties any amount of power that SMGT ultimately does not continue to purchase from PPL EnergyPlus.

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)

In July 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act 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 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, and the CFTC generally has postponed implementation until the later of July 16, 2012 or when required key final rules are issued (e.g. definitional rules for "swap" and "swap dealer"). In order to comply with implementing regulations of the Dodd-Frank Act, the Registrants likely will be faced with significant new recordkeeping and reporting requirements. Also, the Registrants could face significantly higher operating costs or may be required to post additional collateral if they are subject to 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. 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 material 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 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. 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 and the litigation is moving forward. 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.

Although PPL and its subsidiaries believe that 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 November 1998, the FERC authorized LG&E and KU and, in December 1998, authorized PPL EnergyPlus to make wholesale sales of electric power and related products at market-based rates. In those orders, the FERC directed LG&E and 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 region and PPL's market-based rate update for the Western region. 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 Big Rivers Electric Corporation 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, 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. The FERC has indicated it intends to vigorously enforce the Reliability Standards using, among other means, civil penalty authority. Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations. The first group of Reliability Standards approved by the FERC became effective in June 2007.

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 determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC. 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 the course of implementing its program 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.

Due to the environmental issues discussed below or other environmental matters, PPL subsidiaries may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies or courts.

The Clean Air Act addresses, among other things, emissions causing acid deposition, installation of best available control technologies for new or substantially modified sources, attainment of national ambient air quality standards, toxic air emissions and visibility standards in the U.S. Amendments to the Clean Air Act requiring additional emission reductions have been proposed but are unlikely to be introduced or passed in this Congress. The Clean Air Act allows states to develop more stringent regulations and in some instances, as discussed below, Kentucky, Pennsylvania and Montana have done so.

To comply with air-related requirements and other environmental requirements as described below, PPL's forecast for capital expenditures reflects a best estimate projection of expenditures that may be required within the next five years. Such projections are a combined $3.1 billion for LG&E and KU. These projections include $100 million for LG&E and $400 million for KU associated with currently approved ECR plans through 2013 to achieve emissions reductions and manage coal combustion residuals. The projections also include $1.4 billion for LG&E and $900 million for KU associated with the recently approved 2011 ECR Plans for additional expenditures to comply with new clean air rules and manage coal combustion residuals and an additional $300 million for other environmental expenditures. Such projections for PPL Energy Supply are $130 million. Actual costs (including capital, allowance purchases and operational modifications) may be significantly lower or higher depending on the final requirements and market conditions. Certain environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are subject to recovery through the ECR. See Note 6 for additional information on LG&E and KU's ECR plan.

In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. The CSAPR replaces the EPA's previous Clean Air Interstate Rule (CAIR) which was struck down 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 and the proposed Transport Rule, the CSAPR only applies to PPL's coal generation facilities located in Kentucky and Pennsylvania.

The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxides. The CSAPR established new sulfur dioxide emission allowance cap and trade programs that are completely independent of, and more stringent than, the current Acid Rain Program. The CSAPR also established new nitrogen oxides emission allowance cap and trade programs to replace the current programs. All trading is more restrictive than previously under CAIR. The CSAPR provides for two-phased programs of sulfur dioxide and nitrogen oxide emissions reductions, with initial reductions in 2012 and more stringent reductions in 2014.

In December 2011, the Court stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be released as early as May 2012.

With respect to the Kentucky coal-fired generating plants, the stay of the CSAPR will initially only impact the unit dispatch order. With the return of the CAIR and the Kentucky companies' significant number of sulfur dioxide allowances, those units will be dispatched with lower operating cost, but slightly higher sulfur dioxide and nitrogen oxide emissions. However, a key component of the Court's final decision, even if the CSAPR is upheld, will be whether the ruling delays the implementation of the CSAPR by one year for both Phases I and II, or instead still requires the significant sulfur dioxide and nitrogen oxide reductions associated with Phase II to begin in 2014. LG&E's and KU's CSAPR compliance strategy is based on over-compliance during Phase I to generate allowances sufficient to cover the expected shortage during the first two years of Phase II (2014 and 2015) when additional pollution control equipment will be installed. Should Phase I of the CSAPR be shortened to one year, it will be more difficult and costly to provide enough excess allowances in one year to meet the shortage projected for 2014 and 2015.

PPL Energy Supply's coal fired power plants can meet both the CAIR and the proposed CSAPR sulfur dioxide emission requirements with the existing scrubbers that went in-service in 2008 and 2009. For nitrogen oxide, under both the CAIR and the proposed CSAPR, PPL Energy Supply would need to buy allowances or make operational changes, the cost of which is not anticipated to be significant.

In addition to the reductions in sulfur dioxide and nitrogen oxide emissions required under the CSAPR for the Pennsylvania and Kentucky plants, PPL's coal 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. The EPA has recently 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 in attainment or that are unclassifiable, states are required to develop maintenance plans by mid-2013 that demonstrate continued attainment. PPL, PPL Energy Supply, LKE, LG&E and KU anticipate that some of the measures required for compliance with the CSAPR such as upgraded or new sulfur dioxide scrubbers at some of their plants or, in the case of LG&E and KU, upgraded or new sulfur dioxide scrubbers at the Mill Creek plant and retirement of the Cane Run, Green River, and Tyrone plants, will also be necessary to achieve compliance with the new one-hour sulfur dioxide standard. If additional reductions were to be required, the economic impact could be significant.

In May 2011, the EPA published a proposed regulation providing for stringent reductions of mercury and other hazardous air pollutants. On February 16, 2012, the EPA published the final rule, known as the Mercury and Air Toxics Standards (MATS), with an effective date of April 16, 2012. 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 sorbent injection and fabric-filter baghouses to remove certain hazardous air pollutants. Recovery of the cost of certain controls was granted by KPSC order issued in December 2011. The cost for these controls is reflected in the combined costs of $3.1 billion for LG&E and KU noted under "Air" above. LG&E and KU have also announced the anticipated retirement of coal-fired generating units at the Cane Run, Green River, and Tyrone plants and have filed requests with the KPSC for replacement of those units with natural gas-fired generating units to be constructed or purchased. With the publication of the final MATS rule, LG&E and KU are currently assessing whether changes in the final rule warrant revision of their approved compliance plans. With respect to PPL Energy Supply's Pennsylvania plants, PPL believes that these plants are reasonably well controlled and require installation of chemical additive systems, the cost of which is not expected to be material. With respect to PPL Montana plants, modifications to the current air pollution controls installed on Colstrip may be required, the cost of which also is not expected to be material. For the Corette plant, additional controls are being evaluated, the cost of which could be significant. PPL Energy Supply, LG&E and KU are continuing to conduct in-depth reviews of the MATS.

In January 2012, the EPA proposed limited approval of the Pennsylvania Regional Haze State Implementation Plan. That proposed action 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 rule. Previously, the EPA had determined that implementation of the CAIR requirements would meet regional haze BART (Best Available Retrofit Technology) requirements for sulfur dioxide and nitrogen oxides. In December 2011, the EPA proposed that implementation of the CSAPR would also meet the BART. This is expected to address that deficiency.

In Montana, the EPA Region 8 is developing 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 matter emissions for Colstrip Units 1 and 2 and Corette. PPL's analyses concluded that further reductions are not warranted. The EPA responded to PPL's reports for Colstrip and Corette and requested further information and analysis. PPL completed further analysis and submitted addendums to its initial reports for Colstrip and Corette. In February 2009, PPL received an information request for data related to the non-BART-affected emission sources of Colstrip Units 3 and 4. PPL responded to this request in March 2009.

In November 2010, PPL Montana received a request from the EPA Region 8, under the EPA's Reasonable Further Progress goals of the Regional Haze Rules, to provide further analysis with respect to Colstrip Units 3 and 4. PPL completed a high-level analysis of various control options to reduce emissions of sulfur dioxide and particulate matter for these units, and submitted that analysis to the EPA in January 2011. The analysis shows that any incremental reductions would not be cost effective and that further analysis is not warranted. PPL also concluded that further analysis for nitrogen oxides was not justifiable as these units installed controls under a Consent Decree in which the EPA had previously agreed that, when implemented, would satisfy the requirements for installing the BART for nitrogen oxides. The EPA is expected to issue a proposed Federal Implementation Plan for Montana in March 2012. Discussions with the EPA are ongoing with respect to this issue.

PPL and PPL Energy Supply cannot predict whether any additional reductions in emissions will be required in Pennsylvania or Montana. If additional reductions are required, the economic impact could be significant depending on what is required.

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 state implementation plan (SIP) to the EPA which requires the Mill Creek plant to reduce its sulfuric acid mist emissions from Units 3 and 4. After approval of the Kentucky SIP by the EPA and revision of the Mill Creek plant's Title V air permit, LG&E intends to install sorbent injection controls at the plant to reduce sulfuric acid mist emissions. In the event that the EPA determines that compliance with the CSAPR would be insufficient to meet the BART requirements, it would be necessary for LG&E and KU to reassess their planned compliance measures.

The NSR regulations require major new or modified sources of regulated pollutants to receive pre-construction and operating permits with limits that prevent the significant deterioration of air quality in areas that are in attainment of the ambient air quality standards for certain pollutants.

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 several years ago 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. 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 and KU received information requests for their Mill Creek, Trimble County, and Ghent plants, but 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 generating 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. KU has exchanged settlement proposals and other information with the EPA regarding imposition of additional permit limits and emission controls and anticipates continued settlement negotiations. In addition, any settlement or future litigation could potentially encompass a September 2007 notice of violation alleging opacity violations at the plant. Depending on the provisions of a final settlement or the results of litigation, if any, resolution of this matter could involve significant increased operating and capital expenditures. PPL, LKE and KU cannot predict the final outcome of this matter, but currently do not expect such outcome to result in material losses above the respective amounts accrued by KU.

If PPL subsidiaries are found to have violated NSR regulations, PPL 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 initiated enforcement actions and litigation alleging violations of the NSR regulations by coal-fired plants, and PPL is unable to predict whether such actions will be brought against any of PPL's plants.

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 currently 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 considered during the 111th Congress, the outcome of the 2010 elections has halted the debate on such legislation in the current 112th Congress. The timing and elements of any future legislation addressing GHG emission reductions are uncertain at this time. In the current Congress, legislation barring the EPA from regulating GHG emissions under the existing authority of the Clean Air Act has been passed by the U.S. House of Representatives. Various bills providing for barring or delaying the EPA from regulating GHG emissions have been introduced in the U.S. Senate, but the prospects for passage of such legislation remain uncertain. At the state level, the 2010 elections in Pennsylvania have also reduced the likelihood of GHG legislation in the near term, and there are currently no prospects for such legislation in Kentucky or Montana.

As a result of the April 2007 U.S. Supreme Court decision that the EPA has the authority to regulate GHG emissions from new motor vehicles under the Clean Air Act, in April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that apply to 2012 model year vehicles. The EPA has also clarified that this standard triggers regulation of GHG emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act starting in 2011. This means that any new sources or major modifications to existing sources causing a net significant emissions increase requires the BACT permit limits for GHGs. The EPA recently proposed guidance for conducting a BACT analysis for projects that trigger such a review. In addition, New Source Performance Standards for new and existing power plants were expected to be proposed in September 2011 and finalized in May 2012, but this has been delayed. The EPA is expected to announce a new schedule for this rulemaking in the future.

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 3 MW. The MOU also provides for a 10% reduction in carbon dioxide emissions from base levels by 2019.

Pennsylvania has not stated an intention to join the RGGI, but has 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 which identifies 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 the solar supply requirements and restrict eligible solar projects to those located in Pennsylvania. PPL cannot predict at this time whether this legislation will be enacted.

Eleven Western states, including Montana and certain Canadian provinces, are members of the Western Climate Initiative (WCI). The WCI has established a goal of reducing carbon dioxide emissions 15% below 2005 levels by 2020 and is currently developing GHG emission allocations, offsets, and reporting recommendations.

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 yet to issue 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 facilities, 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 Comer v. Murphy Oil, the U.S. Court of Appeals for the 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 Court of Appeals' 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. 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 2011, PPL's power plants emitted approximately 74 million tons of carbon dioxide compared with 68 million tons in 2010. The totals reflect 36 million tons from PPL Generation and 38 million tons from LG&E's and KU's generating fleet. All tons are U.S. short tons (2,000 lbs/ton).

There has been interest in renewable energy legislation at both the state and federal levels. At the federal level, House and Senate bills proposed in the 111th Congress would have imposed mandatory renewable energy supply and energy efficiency requirements in the 15% to 20% range by approximately 2020. Earlier in 2011, there were discussions regarding a Clean Energy Standard (CES) that addressed not only renewables but also encouraged clean energy requirements (as yet to be defined). At this time, neither the renewable energy debate nor the CES discussion is expected to gain momentum at the federal or state levels (beyond what is otherwise already required in Pennsylvania and Montana) in the near term.

PPL believes there are financial, regulatory and logistical uncertainties related to GHG reductions and the implementation of renewable energy mandates. These will need to be resolved before the impact of such requirements on PPL can be meaningfully estimated. Such uncertainties, among others, include the need to provide back-up supply to augment intermittent renewable generation, potential generation oversupply 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. These uncertainties are not directly addressed by proposed legislation. PPL and PPL Energy Supply cannot predict at this time the effect on their future competitive position, results of operation, cash flows and financial position of any GHG emissions, renewable energy mandate or other global climate change requirements 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 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 have very significant impacts on any coal-fired plant, and would require plants to retrofit their operations to comply with full hazardous waste requirements for the generation of CCRs and associated waste waters through 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 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. Comments were submitted on the NODA in November 2011. In addition, the U.S. House of Representatives in October 2011 approved a bill to modify Subtitle D of the RCRA to provide for the proper management and disposal of CCRs and that would preclude the EPA from regulating CCRs under Subtitle C of the RCRA. The bill has been introduced in the Senate and the prospect for passage of this legislation 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 hard deadline for EPA to issue strict CCR regulations. In February 2012, a CCR recycling company also issued a 60-day notice of intent to sue the EPA over its timeliness in issuing CCR regulations, but that company requests that the EPA take a Subtitle D approach that would allow for continued recycling of CCRs.

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 economic impact could be significant.

In 2005, there was a release of approximately 100 million gallons of water containing fly ash 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 DEP submitted its National Resource Damage Assessment report to the court and to the intervenors. The intervenors have commented on the report and the PADEP and PPL recently filed separate responses with the court. The settlement agreement for the Natural Resources Damage Claim has not yet been submitted to the court or for public comments.

Through December 31, 2011, 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 exact nature of any other regulatory or other 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 material losses above the amounts currently recorded.

Seepages or groundwater infiltration have been detected at active and retired wastewater basins and landfills at various PPL plants. PPL has completed or is completing assessments of seepages or groundwater infiltration at various facilities and is 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 claims from seepage from wastewater ponds at Colstrip. 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 that 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 have appealed the October order to the Montana Supreme Court, which is presently being briefed. The parties are in the process of submitting their briefs to the Montana Supreme Court. That court's decision is expected in the second half of 2012. The settlement ordered by the district court is, therefore, not final and PPL and PPL Energy Supply cannot predict the outcome of the appeal, although PPL Montana's share of any final settlement in excess of amounts recorded is not expected to be significant.

In April 2007, PennEnvironment and the Sierra Club brought a Clean Water Act citizen suit in the U.S. District Court for the Western District of Pennsylvania (the Western District Court) against GenOn Northeast Management Company (then known as Reliant Energy Northeast Management Company) (GenOn), as operator of Conemaugh Generating Station (CGS), seeking civil penalties and injunctive relief for alleged violations of CGS's NPDES water discharge permit. A PPL Energy Supply subsidiary holds a 16.25% undivided, tenant-in-common ownership interest in CGS.

Throughout the relevant time period, the operators of CGS have worked closely with the PADEP to ensure that the facility is operated in a manner that does not cause any adverse environmental impacts to the Conemaugh River, a waterway already significantly impacted by discharges from abandoned coal mines and other historical industrial activity with respect to which neither PPL nor CGS had any involvement. Pursuant to a Consent Order and Agreement between the PADEP and GenOn (the CGS COA), a variety of studies have been conducted, a water treatment facility for cooling tower blowdown has been designed and built, and a second treatment facility for sulfur dioxide scrubber waste water has been designed (and is awaiting final PADEP approval for construction), all in order to comply with the stringent limits set out in CGS's NPDES permit.

In March 2011, the Western District Court entered a partial summary judgment in the plaintiffs' favor, declaring that discharges from CGS violated the NPDES permit. Subsequently, the parties agreed to settle the dispute and in August 2011 the court entered a Consent Decree and Order resolving the mater. PPL Energy Supply's share of the settlement is not significant.

In a separate matter, the PADEP plans to file a complaint in the Commonwealth Court of Pennsylvania alleging several violations of Clean Streams Law at the Conemaugh generating facility. The PADEP and GenOn Northeast Management Company, the operator, signed and lodged with the court a consent decree that when entered by the court will resolve the issues. It is expected that the court will enter the consent decree in March 2012 after a 30-day public comment period has lapsed. Under the terms of the consent decree, GenOn will be obligated to pay a civil penalty of $500,000. PPL Energy Supply is responsible for 16.25% of this amount.

In 2006, the EPA significantly decreased to 10 parts per billion (ppb) the drinking water standards related to 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 times, 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 facilities, 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. PPL, PPL Energy Supply, LKE, LG&E and KU 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.

The EPA finalized requirements in 2004 for new or modified cooling water intake structures. These requirements affect where generating facilities are built, establish intake design standards and could lead to requirements for cooling towers at new and modified power plants. Another rule, finalized in 2004, that addressed existing structures was withdrawn following a 2007 decision by the U.S. Court of Appeals for the Second Circuit. 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 in April 2011. The industry and PPL reviewed the proposed rule and submitted comments. The EPA is evaluating comments and meeting with industry groups to discuss options. The final rule is to be issued by July 2012. 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 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 remaining useful life of the plant. PPL, PPL Energy Supply, LKE, LG&E and KU will be unable to determine the exact impact 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.

In October 2009, the EPA released its Final Detailed Study of the Steam Electric Power Generating effluent limitations guidelines and standards. Final regulations are expected to be effective in January 2014. PPL expects the revised guidelines and standards to be more stringent than the current standards especially for sulfur dioxide scrubber wastewater and ash basin discharges, which could result in more stringent discharge permit limits. In the interim, PPL is unable to predict whether the EPA and the states may impose more stringent limits on a case-by-case best professional judgment basis under existing authority as permits are renewed.

PPL has signed a Consent Order and Agreement (the Brunner COA) with the PADEP 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. PPL is in the process of constructing a barrier to prevent debris from entering the river water intake area at a cost which is not expected to be material.

PPL has also investigated alternatives to exclude fish from the discharge channel and submitted three alternatives to the PADEP. According to the Brunner COA, once the cooling towers at Brunner Island became operational, PPL must implement one of these fish exclusion alternatives if a fish kill occurs in the discharge channel due to thermal impacts from the plant. Following start-up of the cooling towers in April 2010, several hundred dead fish were found in the cooling tower intake basket although there were no sudden changes in water temperature. In the third quarter of 2010, PPL discussed this matter with the PADEP and both parties agreed that this condition was not one anticipated by the Brunner COA, thereby concluding it did not trigger a need to implement a fish exclusion project. At this time, no fish exclusion project is planned.

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 state 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" (WOUS) 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 as a result of any eventual expansion of this interpretation cannot reliably be estimated at this time.

PPL Electric is a potentially responsible party 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 significantly 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 facilities 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.

In June 2011, Lepore-Moyers Partnership (LMP) filed a complaint in federal district court against PPL Electric, UGI Corporation and a neighboring property owner relating to contamination allegedly emanating from the former Mount Joy Manufactured Gas Plant (MGP) site located in Lancaster County, Pennsylvania. LMP owns property adjacent to the Mount Joy MGP site and claims that environmental testing done on its property indicates the presence of volatile organic compounds in the soil and/or groundwater. LMP claims that defendants are responsible for, among other things, the reimbursement of costs, future response costs, investigation and remediation of the contamination, and damages caused by the contamination. PPL Electric expects the costs related to this matter to be insignificant.

Depending on the outcome of investigations at sites where investigations have not begun or been completed or developments at sites for which PPL currently lacks information, the costs of remediation and other liabilities could be substantial. PPL and its subsidiaries also could incur other non-remediation costs at sites included in current consent orders or other contaminated sites which could be significant. PPL is unable to 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 facilities. PPL 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, 2011, PPL Energy Supply had accrued a discounted liability of $24 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 8.15%. Expected undiscounted payments are estimated at $2 million for 2012, $1 million for each of the years from 2013 through 2016, and $133 million for work after 2016.

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

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

Concerns have been expressed by some members of the public regarding potential health effects of power frequency EMFs, which are emitted by all devices carrying electricity, including electric transmission and distribution lines and substation equipment. Government officials in the U.S. and the U.K. have reviewed this issue. The U.S. National Institute of Environmental Health Sciences concluded in 2002 that, for most health outcomes, there is no evidence that EMFs cause adverse effects. The agency further noted that there is some epidemiological evidence of an association with childhood leukemia, but that the evidence is difficult to interpret without supporting laboratory evidence. The U.K. National Radiological Protection Board (part of the U.K. Health Protection Agency) concluded in 2004 that, while the research on EMFs does not provide a basis to find that EMFs cause any illness, there is a basis to consider precautionary measures beyond existing exposure guidelines. The Stakeholder Group on Extremely Low Frequency EMF, set up by the U.K. Government, has issued two reports, one in April 2007 and one in June 2010, describing options for reducing public exposure to EMF. The U.K. Government responded to the first report in 2009, agreeing to some of the proposals, including a proposed voluntary code to optimally phase 132 kilovolt overhead lines to reduce public exposure to EMF where it is cost effective to do so. In February 2011, the U.K. Government and the Energy Networks Association agreed to voluntary codes of practice under which new high voltage lines will be designed and operated using optimal phasing to reduce EMF unless doing so would be unreasonable, and defining the circumstances under which utilities will need to provide evidence of compliance with EMF exposure limits adopted by the U.K. Government. The U.K. Government is currently considering the second report which concentrates on EMF exposure from distribution systems. PPL and its subsidiaries believe research on EMF and health issues should continue and are taking steps to reduce EMFs, where practical, in the design of new transmission and distribution facilities. PPL and its subsidiaries are unable to predict what effect, if any, the EMF issue might have on their operations and facilities either in the U.S. or the U.K., and the associated cost, or what, if any, liabilities they might incur related to the EMF issue.

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 $44 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.

The U.K.'s 2008 Climate Change Act imposes a duty on certain companies, including WPD, to report on climate change adaptation. The first information request was received by WPD in March 2010 and submissions for all four distribution network operators were made in June 2011. In October 2011, the U.K. Government confirmed that the reports submitted by WPD fulfill the obligations imposed by Climate Change Act. WPD has worked with other U.K. electricity network operators to undertake research with the internationally recognized U.K. Met Office (the national weather service) and to report using common agreed methodology.

There are no other material legal or administrative proceedings pending against or related to WPD with respect to environmental matters. See "Electric and Magnetic Fields" above for a discussion of EMFs.

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, 2011, this maximum assessment was $44 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 Amendments under the Energy Policy Act of 2005. 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 Amendments under the Energy Policy Act of 2005, PPL Susquehanna could be assessed up to $235 million per incident, payable at $35 million per year.

At December 31, 2011, the property, replacement power and nuclear incident insurers maintained an A.M. Best financial strength rating of A ("Excellent").

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 enter.

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

The table below details guarantees provided as of December 31, 2011. The total recorded liability at December 31, 2011 and 2010 was $14 million for PPL and $11 million for LKE. Other than as noted in the descriptions for "WPD guarantee of pension and other obligations of unconsolidated entities," the probability of expected payment/performance under each of these guarantees is remote.

	Exposure at			Expiration
	December 31, 2011 (a)			Date
PPL
Indemnifications for sale of PPL Gas Utilities	$	300	(b)
Indemnifications related to the WPD Midlands acquisition			(c)
WPD indemnifications for entities in liquidation and sales of assets		287	(d)	2014 - 2018
WPD guarantee of pension and other obligations of unconsolidated entities		88	(e)	2015
Tax indemnification related to unconsolidated WPD affiliates		8	(f)	2012

PPL Energy Supply (g)
Letters of credit issued on behalf of affiliates		21	(h)	2012 - 2014
Retrospective premiums under nuclear insurance programs		44	(i)
Nuclear claims assessment under The Price-Anderson Act Amendments under The Energy Policy Act of 2005		235	(j)
Indemnifications for sales of assets		338	(k)	2012 - 2025
Indemnification to operators of jointly owned facilities		6	(l)
Guarantee of a portion of a divested unconsolidated entity's debt		22	(m)	2018


PPL Electric (n)
Guarantee of inventory value		14	(o)	2016

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

LG&E and KU (q)
LG&E and KU guarantee of shortfall related to OVEC			(r)	2040

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

(b) PPL has provided indemnification to the purchaser of PPL Gas Utilities and Penn Fuel Propane, LLC 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 certain pre-closing unknown environmental liabilities relating to former manufactured gas plant properties or off-site disposal sites, if any, outside of Pennsylvania. The indemnification provisions for most representations and warranties, including tax and environmental matters, are capped at $45 million, in the aggregate, and are triggered (i) only if the individual claim exceeds $50,000, and (ii) only if, and only to the extent that, in the aggregate, total claims exceed $4.5 million. The indemnification provisions for most representations and warranties expired on September 30, 2009 without any claims having been made. Certain representations and warranties, including those having to do with transaction authorization and title, survive indefinitely, are capped at the purchase price and are not subject to the above threshold or deductible. The indemnification provision for the tax matters representations survives for the duration of the applicable statute of limitation. The indemnification provision for the environmental matters representations expired on September 30, 2011 without any claims having been made. The indemnification for covenants survives until the applicable covenant is performed and is not subject to any cap.

(c) WPD Midlands Holdings Limited (formerly Central Networks Limited) had agreed prior to the acquisition 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 there is no expiration date in the transaction documents.

(d) 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.

(e) 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, 2011, 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.

(f) Two WPD unconsolidated affiliates were refinanced during 2005. Under the terms of the refinancing, WPD has indemnified the lender against certain tax and other liabilities.

(g) Other than the letters of credit, all guarantees of PPL Energy Supply, on a consolidated basis, also apply to PPL on a consolidated basis for financial reporting purposes.

(h) 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.

(i) 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.

(j) 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.

(k) 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.

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 are 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. 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 obligations are subject to certain customary limitations, including thresholds for allowable claims, caps on aggregate liability, and time limitations for claims arising out of breaches of representations and warranties. The indemnification provisions for certain representations and warranties expired in the second quarter of 2011.

Subsidiaries of PPL Energy Supply have agreed to provide indemnification to the purchasers of certain non-core generation facilities sold in March 2011 (see Note 9 for additional information) 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 are 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.

(l) 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 maximum obligation among all owners, for each plant, is currently $20 million. 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 agreements do not have an expiration date.

(m) 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 in the event PPL Energy Supply is required to make a payment under the guarantee. Exposure noted reflects principal only. See Note 9 for additional information on the sale of this interest.

(n) All guarantees of PPL Electric and LKE, on a consolidated basis, also apply to PPL on a consolidated basis for financial reporting purposes.

(o) 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.

(p) LKE provides certain indemnifications, the most significant of which relate to the termination of the WKE lease in July 2009. 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 non-excluded government fines and penalties fall outside the cumulative cap. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. Certain matters are currently under discussion among the parties, including one matter currently in arbitration and a further matter for which LKE is contesting the applicability of the indemnification requirement. The matter in arbitration may be ruled upon during early 2012, which ruling may result in increases or decreases to the liability estimate LKE has currently recorded. The ultimate outcome of both matters 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 amount limits 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. No additional material loss is anticipated by reason of such indemnification.

(q) All guarantees of LG&E and KU also apply to LKE on a consolidated basis for financial reporting purposes.

(r) As described in the "Energy Purchase Commitments" section of this footnote, pursuant to a power purchase agreement with OVEC, LG&E and KU are obligated to pay a demand charge which includes, among other charges, decommissioning costs, postretirement and post employment benefits. The demand charge is expected to cover LG&E's and KU's shares of the cost of these 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.

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.