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

		Maximum
		Maturity
Contract Type		Date

Fuels (a)		2023
Limestone		2030
Natural Gas Storage		2015
Natural Gas Transportation		2032
Power, excluding wind		2021
RECs		2021
Wind Power		2027

(a) PPL Energy Supply incurred pre-tax charges of $29 million during 2012 to reduce its 2012 and 2013 contracted coal deliveries. These charges were recorded to "Fuel" on the Statement of Income.

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

		Maximum
		Maturity
Contract Type		Date

Coal		2019
Coal Transportation and Fleeting Services		2024
Natural Gas Storage		2024
Natural Gas Transportation		2024

LG&E and KU have a power purchase agreement with OVEC expiring in June 2040. See footnote (i) to the table in "Guarantees and Other Assurances" below for information on the OVEC power purchase contract. 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 years ended December 31 as follows:

In May 2012, PPL Electric filed a plan with the PUC to purchase its electricity supply for default customers for the period June 2013 through May 2015. The PUC approved the plan in January 2013. The approved plan provides that PPL Electric procure this electricity through competitive solicitations twice each plan year beginning in April 2013. The solicitations will include layered short-term full-requirement products ranging from three months to 12 months for residential and small commercial and industrial PLR customers as well as a recurring 12 month spot market product for large commercial and industrial PLR customers. To date, two of four solicitations have been completed.

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

In connection with its marketing activities or hedging strategy for its power plants, PPL Energy Supply has entered into long-term power sales contracts that extend into 2020, excluding long-term renewable energy agreements that extend into 2038.

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

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

The Kerr Dam Project license (50-year term) was issued by the FERC jointly to Montana Power and the Confederated Salish and Kootenai Tribes of the Flathead Nation in 1985, and requires PPL Montana (as successor licensee to Montana Power) to hold and operate the project for at least 30 years (to 2015). Between 2015 and 2025, the tribes have the option to purchase, hold and operate the project for the remainder of the license term, which expires in 2035. Although the tribes have indicated their intent to exercise the option at the earliest possible date, PPL Montana cannot predict if and when this option will be exercised.

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 $29 million between 2014 and 2040.

In September 2013, PPL Montana reached an agreement to sell its hydroelectric facilities to NorthWestern. The agreement includes PPL Montana's 11 hydroelectric power plants and the company's Hebgen Lake reservoir. See Note 8 for additional information.

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

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

As previously reported, in February 2012 the U.S. Supreme Court issued a decision overturning decisions by the Montana First Judicial District Court and the Montana Supreme Court which had held that the streambeds underlying PPL Montana's hydroelectric generating facilities were owned by the State of Montana and that PPL Montana owed the State of Montana compensation for its prior use of those streambeds. As a result of the U.S. Supreme Court decision, PPL Montana reversed its total loss accrual resulting in a $65 million net credit to "Other operation and maintenance" and a $10 million net credit to "Interest Expense" on the Statement of Income in 2011. The case was remanded by the U.S. Supreme Court to the Montana Supreme Court and, in April 2012, returned by the Montana Supreme Court to the Montana First Judicial District Court. Further proceedings have not been scheduled by the district court.

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

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

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

In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim, including the above receivable, is approximately $375 million, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim and, therefore, no amounts have been recorded in the 2013 financial statements.

In July 2012, PPL Montana received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act at Colstrip Steam Electric Station (Colstrip) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). An Amended Notice was received on September 4, 2012, and a Second Amended Notice was received in October 2012. A Supplemental Notice was received in December 2012. The Notice, Amended Notice, Second Amended Notice and Supplemental Notice (the Notices) were all addressed to the Owner or Managing Agent of Colstrip, and to the other Colstrip co-owners: Avista Corporation, Puget Sound Energy, Portland General Electric Company, Northwestern Energy and PacificCorp. The Notices allege certain violations of the Clean Air Act, including New Source Review, Title V and opacity requirements.

On March 6, 2013, the Sierra Club and MEIC filed a complaint against PPL Montana and the other Colstrip co-owners in the U.S. District Court, District of Montana, Billings Division. PPL Montana operates Colstrip on behalf of the co-owners. The complaint is generally consistent with the prior Notices and lists 39 separate claims for relief. All but three of the claims allege Prevention of Significant Deterioration (PSD) related violations under the federal Clean Air Act for various plant maintenance projects completed since 1992. For each such project or set of projects, there are separate claims for failure to obtain a PSD permit, for failure to obtain a Montana Air Quality Permit to operate after the project(s) were completed and for operating after completion of such project(s) without "Best Available Control Technology". The remaining three claims relate to the alleged failure to update the Title V operating permit for Colstrip to reflect the alleged major modifications described in the other claims, allege that the previous Title V compliance certifications were incomplete because they did not address the major plant modifications, and that numerous opacity violations have occurred at the plant since 2007. The complaint requests injunctive relief and civil penalties on average of $36,000 per day per violation, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. In January 2014, trial in this matter as to liability was re-scheduled for March 2015. A new date for trial as to remedies, if there is a finding of liability, has not been scheduled.

On July 27, 2013, the Sierra Club and MEIC filed an additional Notice, identifying additional plant projects that are alleged not to be in compliance with the Clean Air Act. On September 27, 2013, the plaintiffs filed an amended complaint. This amended complaint drops all claims regarding pre-2001 plant projects, as well as the plaintiffs' Title V and opacity claims. It does, however, add claims with respect to a number of post-2000 plant projects, which effectively increased the number of projects subject to the litigation by about 40. PPL Montana and the other Colstrip Owners filed a motion to dismiss the amended complaint on October 11, 2013. Although PPL Montana believes it and the other co-owners have numerous defenses to the allegations set forth in this complaint and will vigorously assert the same, PPL Montana cannot predict the ultimate outcome of this matter at this time.

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

The Dodd-Frank Act became effective in July 2010 and includes provisions that impose derivative transaction reporting requirements and require most over-the-counter derivative transactions to be executed through an exchange and to be centrally cleared. The Dodd-Frank Act also provides that the U.S. Commodity Futures Trading Commission (CFTC) may impose collateral and margin requirements for over-the-counter derivative transactions, as well as capital requirements for certain entity classifications. The CFTC is establishing final rules on major provisions in the Dodd-Frank Act through its rulemaking process. Several final rules providing for the definition of the terms "swap", "swap dealer", and "major swap participant" became effective in October 2012. The entity classification thresholds and requirements set forth in these final rules do not require the Registrants to register as either swap dealers or major swap participants. Consequently, as commercial end users, the Registrants are not subject to the heightened regulatory requirements applicable to swap dealers or major swap participants, including Business Conduct Standards, enhanced recordkeeping and reporting, clearing and exchange trading of CFTC-mandated swaps and other complex requirements under other CFTC regulations. The Dodd-Frank Act and its implementing regulations, however, have imposed on the Registrants significant additional and costly recordkeeping, reporting and documentation requirements.

The Registrants could face significantly higher operating costs or may be required to post additional collateral if they or their counterparties are subject to capital or margin requirements as ultimately adopted in the implementing regulations of the Dodd-Frank Act. Additionally, the burden that the Dodd-Frank Act and implementing regulations impose on all market participants could cause decreased liquidity in the bilateral swap market as financial entities discontinue their proprietary trading operations. Decreased liquidity could increase costs for Registrants to successfully meet hedge targets. The Registrants will continue to evaluate the provisions of the Dodd-Frank Act and its implementing regulations, but could incur significant costs related to compliance with the Act and regulations.

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

In addition, in February 2011, PPL, and several other generating companies and utilities filed a complaint in U.S. District Court in New Jersey challenging the Act on the grounds that it violates well-established principles under the Supremacy Clause and the Commerce Clause of the U.S. Constitution and requesting declaratory and injunctive relief barring implementation of the Act by the BPU Commissioners. In October 2011, the court denied the BPU's motion to dismiss the proceeding and in September 2012 the U.S. District Court denied all summary judgment motions. Trial of this matter was completed in June 2013. In October 2013, the U.S. District Court in New Jersey issued a decision finding the Act unconstitutional under the Supremacy Clause on the grounds that it infringes upon the FERC's exclusive authority to regulate the wholesale sale of electricity in interstate commerce. The decision has been appealed to the U.S. Court of Appeals for the Third Circuit by CPV Power Development, Inc., Hess Newark, LLC and the State of New Jersey. Oral arguments are scheduled for March 27, 2014. PPL, PPL Energy Supply and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.

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

In April 2012, PPL and several other generating companies filed a complaint in U.S. District Court in Maryland challenging the MD PSC order on the grounds that it violates well-established principles under the Supremacy and Commerce clauses of the U.S. Constitution and requested declaratory and injunctive relief barring implementation of the order by the MD PSC Commissioners. In August 2012, the court denied the MD PSC and CPV Maryland, LLC motions to dismiss the proceeding. Trial of this matter was completed in March 2013. In September 2013, the U.S. District Court in Maryland issued a decision finding the MD PSC order unconstitutional under the Supremacy Clause on the grounds that it infringes upon the FERC's exclusive authority to regulate the wholesale sale of electricity in interstate commerce. The decision has been appealed to the U.S. Court of Appeals for the Fourth Circuit by CPV Power Development, Inc. and the State of Maryland. 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. In July 2012, PPL Montana and the City of Tacoma, one of the two parties claiming refunds at FERC, reached a settlement whereby PPL Montana paid $75 thousand to resolve the City of Tacoma's $23 million claim. The settlement does not resolve the remaining claim outstanding at December 31, 2013 by the City of Seattle for approximately $50 million. In April 2013, the FERC issued an order on reconsideration allowing the parties to seek refunds for the period January 2000 through December 2000. As a result, the City of Seattle may be able to seek refunds from PPL Montana for such period. Hearings before a FERC Administrative Law Judge regarding the City of Seattle's refund claims were completed in October 2013. Briefing was completed in January 2014 and an initial decision is expected in mid-March 2014.

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

In 1998, the FERC authorized LG&E, KU and PPL EnergyPlus to make wholesale sales of electricity and related products at market-based rates. In those orders, the FERC directed LG&E, KU and PPL EnergyPlus, respectively, to file an updated market analysis within three years after the order, and every three years thereafter. Since then, periodic market-based rate filings with the FERC have been made by LG&E, KU, PPL EnergyPlus, PPL Electric, PPL Montana and most of PPL Generation's subsidiaries. These filings consisted of a Northwest market-based rate filing for PPL Montana and a Northeast market-based rate filing for most of the other PPL subsidiaries in PJM's region. In June 2011, FERC approved PPL's market-based rate update for the Eastern and Western regions and PPL filed its market-based rate update for the Southeast region, including LG&E and KU in addition to PPL EnergyPlus. Also, in June 2011, the FERC issued an order approving LG&E's and KU's request for a determination that they no longer be deemed to have market power in the BREC balancing area and removing restrictions on their market-based rate authority in such region. In December 2013, PPL filed market-based rate updates for the Eastern and Western regions. PPL cannot predict the ultimate outcome of these update filings at this time.

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

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

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

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

In October 2012, the FERC initiated its consideration of proposed changes to Reliability Standards to address the impacts of Geomagnetic Disturbances on the reliable operation of the bulk-power system, which might, among other things, lead to a requirement to install equipment that blocks geo-magnetically induced currents on implicated transformers. On May 16, 2013, FERC issued Order No. 779, requiring NERC to submit two types of Reliability Standards for FERC's approval in twelve month intervals. The first type would require certain owners and operators of the nation's electricity infrastructure, such as the Registrants, to develop and implement operational procedures to mitigate the effects of Geomagnetic Disturbances on the bulk-power system. This NERC proposed standard was filed by NERC with FERC for approval in January of 2014, with a comment due date of March 24, 2014. The second type is to require owners and operators of the bulk-power system to assess certain Geomagnetic Disturbance events and develop and implement plans to protect the bulk-power system from those events and must be filed by NERC with FERC for approval by January 22, 2015. The Registrants may be required to make significant expenditures in new equipment or modifications to their facilities to comply with the new requirements. The Registrants are unable to predict the amount of any expenditures that may be required as a result of the adoption of any Reliability Standards for Geomagnetic Disturbances.

In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. PPL Susquehanna recorded credits totaling $56 million to "Fuel" on the Statement of Income in 2011 to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. The amounts recorded through September 2011 cover costs incurred from 1998 through December 2010. PPL Susquehanna is eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that are incurred through December 31, 2013. In exchange, PPL Susquehanna has waived any claims against the United States government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna plant through December 31, 2013. In January 2014, PPL Susquehanna entered into a new agreement with the Department of Energy to extend the settlement agreement on the same terms as the prior agreement for an additional three years to the end of 2016.

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

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

In July 2011, the EPA adopted the CSAPR. The CSAPR replaced the EPA's previous CAIR which was invalidated in July 2008 by the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court). CAIR subsequently was effectively reinstated by the D.C. Circuit Court in December 2008, pending finalization of the CSAPR. Like CAIR, CSAPR targeted sources in the eastern U.S. and would have required reductions in sulfur dioxide and nitrogen oxides in two phases (2012 and 2014).

In December 2011, the D.C. Circuit Court stayed implementation of the CSAPR and left CAIR in effect pending a final decision on the validity of the rule. In August 2012, the D.C. Circuit Court issued a ruling invalidating CSAPR, remanding the rule to the EPA for further action, and leaving CAIR in place during the interim. In June 2013, the U.S. Supreme Court granted the EPA's petition for review of the D.C. Circuit Court's August 2012 decision. Oral arguments before the U.S. Supreme Court were held in December 2013. Prior to a revised transport rule from the EPA, coal-fired generating plants could face tighter emission limitations on nitrogen oxides through state action.

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

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

PPL fossil-fueled generating plants may face further reductions in emissions as a result of more stringent national ambient air quality standards for ozone, nitrogen oxides, sulfur dioxide and/or fine particulates.

In 2010, the EPA finalized a new one-hour standard for sulfur dioxide and required states to identify areas that meet those standards and areas that are in non-attainment. In July 2013, the EPA finalized non-attainment designations for parts of the country, including part of Yellowstone County in Montana (Billings area) and part of Jefferson County in Kentucky. Attainment must be achieved by 2018. States are working on designations for other areas.

In December 2012, the EPA issued final rules that strengthen the fine particulate standards. Under the final rules, states and the EPA have until 2015 to identify non-attainment areas, and states have until 2020 to achieve attainment for those areas.

PPL, PPL Energy Supply, LKE, LG&E and KU anticipate that some of the measures required for compliance with the CAIR, or the MATS, or the Regional Haze requirements (as discussed below), such as upgraded or new sulfur dioxide scrubbers at certain plants and, in the case of LG&E and KU, the previously announced retirement of coal-fired generating units at the Cane Run, Green River and Tyrone plants, will help to achieve compliance with the new one-hour sulfur dioxide standard. If additional reductions were to be required, the financial impact could be significant. The short-term impact on the Corette plant from the EPA's final designation of part of Yellowstone County in Montana as non-attainment (as noted above) is not expected to be significant, as PPL Energy Supply previously announced its intent to place the plant in long-term reserve status beginning in April 2015.

Until particulate matter and sulfur dioxide maintenance and compliance plans are developed by the EPA and state or local agencies, including identification and finalization of attainment designations for particulate matter, PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict the impact of the new standards.

In May 2011, the EPA published a proposed regulation requiring stringent reductions of mercury and other hazardous air pollutants from power plants. In February 2012, the EPA published the final rule, known as the MATS, with an effective date of April 2012. The rule is being challenged by industry groups and states in the D.C. Circuit Court, where oral arguments were held in December 2013. The rule provides for a three-year compliance deadline with the potential for a one-year extension as provided under the statute. PPL has received compliance extensions for certain plants in Kentucky and Pennsylvania. LG&E, KU and PPL Energy Supply are considering extension requests for other plants as well.

At the time the MATS rule was proposed, LG&E and KU filed requests with the KPSC for environmental cost recovery based on their expected need to install environmental controls including chemical additive and fabric-filter baghouses to remove air pollutants. Recovery of the cost of certain controls was granted by the KPSC in December 2011. LG&E's and KU's anticipated retirement of certain coal-fired electricity generating units located at Cane Run and Green River is in response to MATS and other environmental regulations. LG&E and KU are continuing to assess whether any revisions of their approved compliance plans will be necessary.

With respect to PPL Energy Supply's Pennsylvania plants, PPL Energy Supply believes that installation of chemical additive systems may be necessary at certain coal-fired plants, the capital cost of which is not expected to be significant. PPL Energy Supply continues to analyze the potential impact of MATS on operating costs. With respect to PPL Energy Supply's Montana plants, modifications to the air pollution controls installed on Colstrip may be required, the cost of which is not expected to be significant. For the Corette plant, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place the plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with the MATS requirements. The Corette plant was determined to be impaired in December 2013. See Note 18 for additional information. PPL Energy Supply, LG&E and KU are continuing to conduct in-depth reviews of the MATS, including the potential implications to scrubber wastewater discharges. See the discussion of effluent limitations guidelines and standards below.

The EPA's regional haze programs were developed under the Clean Air Act to eliminate man-made visibility degradation by 2064. Under the programs, states are required to take action via state plans to make reasonable progress every decade, including the application of Best Available Retrofit Technology (BART) on power plants commissioned between 1962 and 1977.

The primary power plant emissions affecting visibility are sulfur dioxide, nitrogen oxides and particulates. To date, the focus of regional haze activity has been the western U.S. because the EPA had determined that the regional trading program in the eastern U.S. under CSAPR satisfied BART requirements to reduce sulfur dioxide and nitrogen oxides. However, the D.C. Circuit Court's August 2012 decision to vacate and remand CSAPR and to implement CAIR in its place on an interim basis leaves power plants located in the eastern U.S., including PPL's plants in Pennsylvania and Kentucky, exposed to reductions in sulfur dioxide and nitrogen oxides as required by BART, unless the D.C. Circuit Court's decision, now pending before the U.S. Supreme Court, is overturned.

In addition to this exposure stemming from the remand of CSAPR, LG&E's Mill Creek Units 3 and 4 are required to reduce sulfuric acid mist emissions because they were determined to have a significant regional haze impact. These reductions are in the Kentucky Division of Air Quality's regional haze state implementation plan that was submitted to the EPA. LG&E is currently installing sorbent injection technology to comply with these reductions, the costs of which are not expected to be significant.

In Montana, the EPA Region 8 developed the regional haze plan as the MDEQ declined to develop a BART state implementation plan. The EPA finalized the plan ("Federal Implementation Plan" or "FIP") in 2012. The final FIP assumed no additional controls for Corette or Colstrip Units 3 and 4, but proposed tighter limits for Corette and Colstrip Units 1 and 2. PPL Energy Supply expects to meet these tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" above). Under the final FIP, Colstrip Units 1 and 2 may require additional controls, including the possible installation of an SNCR and other technology, to meet more stringent nitrogen oxides and sulfur dioxide limits. The cost of these potential additional controls, if required, could be significant. Both PPL and environmental groups have appealed the final FIP rules to the U.S. Court of Appeals for the Ninth Circuit.

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, and PPL and the EPA have exchanged certain information regarding this matter. In January 2009, PPL, PPL Energy Supply and other companies that own or operate the Keystone plant in Pennsylvania received a notice of violation from the EPA alleging that certain projects were undertaken without proper NSR compliance. In May and November 2012, PPL Montana received information requests from the EPA regarding projects undertaken during a Spring 2012 maintenance outage at Colstrip Unit 1. In September 2012, PPL Montana received an information request from the Montana Department of Environmental Quality regarding Colstrip Unit 1 and other projects. PPL and PPL Energy Supply cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.

In March 2009, KU received an EPA notice alleging that KU violated certain provisions of the Clean Air Act's rules governing NSR and prevention of significant deterioration by installing sulfur dioxide scrubbers and SCR controls at its Ghent plant without assessing potential increased sulfuric acid mist emissions. KU contends that the projects in question were pollution control projects, and therefore exempt from the requirements cited by the EPA. In December 2009, the EPA issued an information request on this matter. In September 2012, the parties reached a tentative settlement addressing the Ghent NSR matter that seeks to resolve a September 2007 notice of violation alleging opacity violations at the plant. The parties subsequently entered into a consent decree which was approved by the court on September 11, 2013. The consent decree requires the incurrence of non-material costs that have already been accrued.

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

States and environmental groups also have commenced litigation alleging violations of the NSR regulations by coal-fired generating plants across the nation. See "Legal Matters" above for information on a lawsuit filed by environmental groups in March 2013 against PPL Montana and other owners of Colstrip.

If PPL subsidiaries are found to have violated NSR regulations by significantly increasing pollutants through a major plant modification, PPL, PPL Energy Supply, LKE, LG&E and KU would, among other things, be required to meet stringent permit limits reflecting Best Available Control Technology (BACT) for pollutants meeting the National Ambient Air Quality Standards (NAAQS) in the area and reflecting Lowest Achievable Emission Rates (LAER) for pollutants not meeting the NAAQS in the area. The costs to meet such limits, including installation of technology at certain units, could be significant.

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, in January 2010, were incorporated into a final revised permit issued by the KDAQ. In March 2010, the environmental groups petitioned the EPA to object to the revised state permit. Until the EPA issues a final ruling on the pending petition and all available appeals are exhausted, PPL, LKE, LG&E and KU cannot predict the outcome of this matter or the potential impact on the capital costs of this project, if any.

In the 2011 to 2013 time period, the Louisville Metro Air Pollution Control District issued several notices of violation alleging violations of local air quality rules at the Cane Run plant. In November 2013, LG&E entered into a settlement resolving the pending citations in return for payment of a civil penalty in a non-material amount and performance of remedial measures not expected to result in material costs.

On September 6, 2013, PPL, LKE and LG&E received a letter on behalf of two residents adjacent to the Cane Run plant notifying various federal, state, and local agencies of their intent to file a citizen suit for alleged violations of the Clean Air Act (CAA) and Resource Conservation and Recovery Act (RCRA). On December 16, 2013, six residents, on behalf of themselves and others similarly situated, filed a class action complaint against LG&E and PPL in the U.S. District Court for the Western District of Kentucky for alleged violations of the CAA and RCRA. In addition, these plaintiffs assert common law claims of nuisance, trespass, and negligence. These plaintiffs seek injunctive relief and civil penalties that would accrue to governmental agencies, plus costs and attorney fees, for the alleged statutory violations. Under the common law claims, these plaintiffs seek monetary compensation and punitive damages for property damage and diminished property values for a class consisting of residents within four miles of the plant. In their individual capacities, these plaintiffs seek compensation for alleged adverse health effects. PPL, LKE and LG&E cannot predict the outcome of this matter or the potential impact on operations of the Cane Run plant. LG&E has previously announced that it anticipates retiring the coal-fired units at Cane Run before the end of 2015.

As a result of the April 2007 U.S. Supreme Court decision that the EPA has authority under the Clean Air Act to regulate GHG emissions from new motor vehicles, in April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that applied beginning with 2012 model year vehicles. The EPA also clarified that this standard, beginning in 2011, authorized regulation of GHG emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act. As a result, any new sources or major modifications to existing GHG sources causing a net significant emissions increase now require adherence to the BACT permit limits for GHGs. The rules were challenged, and in June 2012 the D.C. Circuit Court upheld the EPA's regulations. In December 2012, the D.C. Circuit Court denied petitions for rehearing pertaining to its June 2012 opinion. On October 15, 2013, the U.S. Supreme Court granted certiorari for several petitions to decide whether the NSR provisions of the Clean Air Act require the EPA to regulate GHG emissions from stationary sources, such as power plants.

In June 2013, President Obama released his Climate Action Plan which reiterates the goal of reducing greenhouse gas emissions in the U.S. "in the range of" 17% below 2005 levels by 2020 through such actions as regulating power plant emissions, promoting increased use of renewables and clean energy technology, and establishing tighter energy efficiency standards. Also, by Presidential Memorandum the EPA was directed to issue a revised proposal for new power plants (a prior proposal was issued in 2012) by September 20, 2013, with a final rule in a timely fashion thereafter, and to issue proposed standards for existing plants by June 1, 2014 with a final rule to be issued by June 1, 2015. The EPA was further directed to require that states develop implementation plans for existing plants by June 2016. Regulation of existing plants could have a significant industry-wide impact depending on the structure and stringency of the final rule and the state implementation plans. The Administration's recent increase in its estimate of the "social cost of carbon" (which is used to calculate benefits associated with proposed regulations) from $23.80 to $38 per metric ton in 2015 may also lead to more costly regulatory requirements; the White House Office of Management and Budget (OMB) has opened this issue for public comment. Additionally, the Climate Action Plan requirements related to preparing the U.S. for the impacts of climate change could affect PPL and others in the industry as modifications to electricity delivery systems to improve the ability to withstand major storms may be needed in order to meet those requirements.

The EPA issued its revised proposal for new sources on September 20, 2013 as directed by the White House. This proposal was published in the Federal Register on January 8, 2014, with comments due on March 10, 2014. Unlike the EPA's prior proposal, the EPA's revised proposal established separate emission standards for coal and gas units based on the application of different technologies. The coal standard is based on the application of partial carbon capture and sequestration technology, but because this technology is not presently commercially available, the revised proposal effectively precludes the construction of new coal plants. The EPA proposed the same standard for NGCC power plants as was proposed in 2012 and may not be consistently achievable. In addition, the EPA deleted the explicit exemption previously proposed for simple-cycle natural gas plants.

At the regional level, ten northeastern states have been participating in a cap-and-trade program called the Regional Greenhouse Gas Initiative (RGGI). The program commenced in January 2009 and covers electric power plants greater than 25 MW. The program calls for a 10% reduction in carbon dioxide emissions from these plants by 2019 compared to 2005 levels. Pennsylvania has not stated an intention to join the RGGI, but enacted the Pennsylvania Climate Change Act of 2008 (PCCA). The PCCA established a Climate Change Advisory Committee to advise the PADEP on the development of a Climate Change Action Plan. In December 2013, the Advisory Committee issued an updated Climate Change Action Report and identified specific actions that could result in reducing GHG emissions by 30% by 2020. The report recognized some legislative initiatives that were enacted since 2009 that facilitated reductions in GHG emissions and made a number of legislative recommendations that include amending the PA AEPS Act to include additional waste-to-energy facilities, providing incentives for coal mine methane usage, providing incentives for alternative fuel vehicles and addressing the long-term viability issues of carbon capture and sequestration.

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. In November 2011, the Council issued a final report to the Secretary of Kentucky's Energy and Environment Cabinet for his consideration. The final report acknowledged that the recommendations would require additional review and analysis prior to implementation, and that many of the recommendations would likely require, in part, further legislative or regulatory actions. The impact of any such plan is not now determinable, but the costs to comply with the plan could be significant.

A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting plants and, although the decided cases to date have not sustained claims brought on the basis of these theories of liability, 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 Second Circuit and held that such federal common law claims were displaced by the Clean Air Act and regulatory actions of the EPA. In addition, in Comer v. Murphy Oil (Comer case), the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit) declined to overturn a district court ruling that plaintiffs did not have standing to pursue state common law claims against companies that emit GHGs. The complaint in the Comer case named the previous indirect parent of LKE as a defendant based upon emissions from the Kentucky plants. In January 2011, the Supreme Court denied a petition to reverse the Fifth Circuit's ruling. In May 2011, the plaintiffs in the Comer case filed a substantially similar complaint in federal district court in Mississippi against 87 companies, including KU and three other indirect subsidiaries of LKE, under a Mississippi statute that allows the re-filing of an action in certain circumstances. In March 2012, the Mississippi federal district court granted defendants' motions to dismiss the state common law claims. Plaintiffs appealed to the U.S. Court of Appeals for the Fifth Circuit, and in May 2013, the Fifth Circuit affirmed the district court's dismissal of the case. Additional litigation in federal and state courts over such issues is continuing. PPL, LKE and KU cannot predict the outcome of these lawsuits or estimate a range of reasonably possible losses, if any.

In 2013, PPL's power plants emitted approximately 62 million tons of carbon dioxide compared with 70 million tons in 2012. The totals reflect 26 million tons from PPL Energy Supply, and 17 million tons and 19 million tons from LG&E's and KU's generating fleets. All tons are U.S. short tons (2,000 pounds/ton).

There has been interest in renewable energy legislation at both the state and federal levels. Federal legislation on renewable energy is not expected to be enacted this year. In Pennsylvania, bills were introduced calling for an increase in AEPS Tier 1 obligations and to create a $25 million permanent funding program for solar generation. Bills (SB 1171 and HB 100) were also introduced to add natural gas as a qualified AEPS resource, and another bill (HB 1912) would repeal the AEPS Act entirely. A bill adding new hydropower to Montana's renewable portfolio standard was enacted with an effective date of October 1, 2013. An interim legislative committee in Montana is reviewing the state's RPS. PPL and PPL Energy Supply cannot predict at this time whether the committee will recommend any changes to existing laws. In Maryland, bills have been introduced in the 2014 session to double the state's RPS requirement from 20% to 40% and provide exceptions for specific types of energy sources.

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

In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs (as either hazardous or non-hazardous) under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes. Regulating CCRs as a hazardous waste under Subtitle C of the RCRA would materially increase costs and result in early retirements of many coal-fired plants, as it would require plants to retrofit their operations to comply with full hazardous waste requirements for the generation of CCRs and associated waste waters through generation, transportation and disposal. This would also have a negative impact on the beneficial use of CCRs and could eliminate existing markets for CCRs. The EPA's proposed approach to regulate CCRs as non-hazardous waste under Subtitle D of the RCRA 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 EPA's proposed non-hazardous waste regulations, 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 or is implementing 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) requesting comments on selected documents it received during the comment period for the proposed regulations. On September 20, 2013, in response to the proposed Effluent Limitation Guidelines, PPL submitted comments on the proposed CCR regulations. Also, on September 3, 2013, PPL commented on a second CCR NODA seeking comment on additional information related to the EPA's proposal.

A coalition of environmental groups and two CCR recycling companies have filed lawsuits against the EPA seeking a deadline for final rulemaking and, in settlement of that litigation, the EPA has agreed to issue its final rulemaking by the end of 2014.

In July 2013, the U.S. House of Representatives passed House Bill H.R. 2218, the Coal Residuals and Reuse Management Act of 2013, which would preempt the EPA from issuing final CCR regulations and would set non-hazardous CCR standards under RCRA and authorize state permit programs. It remains uncertain whether similar legislation will likely be passed by the U.S. Senate. PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict at this time the final requirements of the EPA's CCR regulations or potential changes to the RCRA and what impact they would have on their facilities, but the financial and operational impact is expected to be material if CCRs are regulated as hazardous waste and significant if regulated as non-hazardous.

In May 2011, LG&E submitted an application for a special waste landfill permit to handle coal combustion residuals generated at the Trimble County plant. After extensive review of the permit application in May 2013, the Kentucky Division of Waste Management denied the permit application on the grounds that the proposed facility would violate the Kentucky Cave Protection Act because it would eliminate an on-site karst feature considered to be a cave. After assessing additional options for managing coal combustion residuals, in January 2014, LG&E submitted to the Kentucky Division of Waste Management a landfill permit application for an alternate site adjacent to the plant. PPL, LKE, LG&E and KU are unable to determine the precise impact of this matter until a landfill permit is issued and any resulting legal challenges are concluded.

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

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

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

The EPA published proposed rule 316(b) for existing facilities in April 2011. The EPA has been evaluating the comments it received to the proposed rule and meeting with industry groups to discuss options. The proposed rule contains two requirements to reduce impact to aquatic organisms at cooling water intake structures. The first requires all existing facilities to meet standards for the reduction of mortality of aquatic organisms that become trapped against water intake screens (impingement) regardless of the levels of mortality actually occurring or the cost to achieve the standards. The second requirement is to determine and install the best technology available to reduce mortality of aquatic organisms pulled through a plant's cooling water system (entrainment). A form of cost-benefit analysis is allowed for this second requirement involving a site-specific evaluation based on nine factors, including impacts to energy delivery reliability and the remaining useful life of the plant. The final rule is expected by April 17, 2014. Until the final rule is issued, PPL, PPL Energy Supply, LKE, LG&E and KU cannot estimate a range of reasonably possible costs, if any, that would be required to comply with such a regulation.

In June 2013, the EPA published proposed regulations to revise discharge limitations for steam electric generation wastewater permits. The proposed limitations are based on the EPA review of available treatment technologies and their capacity for reducing pollutants and include new requirements for fly ash and bottom ash transport water and metal cleaning waste waters, as well as new limits for scrubber wastewater and landfill leachate. The EPA's proposed ELG regulations contain requirements that would affect the inspection and operation of CCR facilities, if finalized. The EPA has indicated that it will coordinate these regulations with the regulation of CCRs discussed above. The proposal contains alternative approaches, some of which could significantly impact PPL's coal-fired plants. PPL, PPL Energy Supply, LKE, LG&E and KU worked with industry groups to comment on the proposed regulation on September 20, 2013. The final regulation is expected to be issued in May 2014 but it may be delayed. At the present time, PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible costs, but the costs could be significant. Pending finalization of the ELGs, certain states and environmental groups (including Pennsylvania and Kentucky) are proposing more stringent technology-based limits in permit renewals. Depending on the final limits imposed, the costs of compliance could be significant and costs could be imposed ahead of federal timelines.

The EPA is reassessing its polychlorinated biphenyls (PCB) regulations under the Toxic 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 or some PCB-containing equipment. The EPA is planning to propose the revised regulations in November 2014. PCBs are found, in varying degrees, in all of the Registrants' operations. The Registrants cannot predict at this time the outcome of these proposed EPA regulations and what impact, if any, they would have on their facilities, but the costs could be significant.

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

In May 2010, the Kentucky Waterways Alliance and other environmental groups filed a petition with the Kentucky Energy and Environment Cabinet challenging the Kentucky Pollutant Discharge Elimination System permit issued in April 2010, which covers water discharges from the Trimble County plant. In November 2010, the Cabinet issued a final order upholding the permit. In December 2010, the environmental groups appealed the order to the Trimble Circuit Court, but the case was subsequently transferred to the Franklin Circuit Court. In September 2013, the court reversed the Cabinet order upholding the permit and remanded the permit to the agency for further proceedings. In October 2013, LG&E filed a notice of appeal with the Kentucky Court of Appeals. 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 U.S." subject to regulation under the Clean Water Act. This change has the potential to affect generation and delivery operations, with the most significant effect being the potential elimination of the existing regulatory exemption for plant waste water treatment systems. The costs that may be imposed on the Registrants as a result of any eventual expansion of this interpretation cannot reliably be estimated at this time but could be significant.

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

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

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

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

Under the Pennsylvania Clean Streams Law, subsidiaries of PPL Generation are obligated to remediate acid mine drainage at former mine sites and may be required to take additional steps to prevent potential acid mine drainage at previously capped refuse piles. One PPL Generation subsidiary is pumping mine water at two mine sites and treating water at one of these sites. Another PPL Generation subsidiary has installed a passive wetlands treatment system at a third site. In December 2013, PPL Generation subsidiaries reached an agreement of sale for one of the two pumping mine sites and the passive wetlands treatment system at the third site. Once these sales are finalized and responsibilities are transferred to the new owner, subject to regulatory agency approvals, PPL Generation subsidiaries will no longer be responsible for operating and maintaining these two sites. At December 31, 2013, PPL Energy Supply had accrued a discounted liability of $21 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 8.21%. Expected undiscounted payments are estimated at $1 million for each of the years from 2014 through 2018, and $107 million for work after 2018.

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

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

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

The Price-Anderson Act is a United States Federal law which governs liability-related issues and ensures the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. Effective September 10, 2013, the liability limit per incident was $13.6 billion for such claims which is funded by insurance coverage from American Nuclear Insurers (ANI) and an industry assessment program.

Under the industry assessment program, in the event of a nuclear incident at any of the reactors covered by The Price-Anderson Act as amended, PPL Susquehanna could be assessed up to $255 million per incident, payable at $38 million per year.

Additionally, PPL Susquehanna purchases property insurance programs from NEIL, an industry mutual insurance company of which PPL Susquehanna is a member. Effective April 1, 2013, facilities at the Susquehanna plant are insured against property damage losses up to $2.50 billion. PPL Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.

Under the NEIL property and replacement power insurance programs, PPL Susquehanna could be assessed retrospective premiums in the event of the insurers' adverse loss experience. Effective April 1, 2013, this maximum assessment was $46 million.

In 2014, certain labor agreement negotiations are scheduled to begin or have begun. For PPL, PPL Energy Supply and PPL Electric, negotiations with the IBEW commenced in January 2014. The current agreement expires in May 2014. For LG&E, negotiations with the IBEW will begin in October 2014. The current agreement expires in November 2014. For KU, the agreement with the IBEW includes a wage reopener in July 2014 and the current agreement expires in August 2015. Additionally, KU's negotiations with the United Steelworkers of America labor union will begin in July 2014 and the current agreement expires in August 2014. The Registrants cannot predict the outcome of the union labor negotiations.

The labor agreements expiring in 2014 covered the following employees at December 31, 2013:

	Number of Employees	Percent of Total Workforce

PPL	3,755	20%
PPL Energy Supply	1,190	24%
PPL Electric	1,419	63%
LKE	774	22%
LG&E	701	70%
KU	73	7%

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

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

The table below details guarantees provided as of December 31, 2013. "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee. The probability of expected payment/performance under each of these guarantees is remote except for "WPD guarantee of pension and other obligations of unconsolidated entities" and "Indemnification of lease termination and other divestitures." The total recorded liability at December 31, 2013 and 2012 was $26 million and $24 million for PPL and $19 million and $20 million for LKE. For reporting purposes, on a consolidated basis, all guarantees of PPL Energy Supply (other than the letters of credit), PPL Electric, LKE, LG&E and KU also apply to PPL, and all guarantees of LG&E and KU also apply to LKE.

	Exposure at			Expiration
	December 31, 2013			Date
PPL
Indemnifications related to the WPD Midlands acquisition			(a)
WPD indemnifications for entities in liquidation and sales of assets	$	12	(b)	2017 - 2018
WPD guarantee of pension and other obligations of unconsolidated entities		127	(c)

PPL Energy Supply
Letters of credit issued on behalf of affiliates		29	(d)	2014 - 2015

Indemnifications for sales of assets		250	(e)	2025
Guarantee of a portion of a divested unconsolidated entity's debt		22	(f)	2018


PPL Electric
Guarantee of inventory value		27	(g)	2017

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

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

(a) Indemnifications related to certain liabilities, including a specific unresolved tax issue and those relating to properties and assets owned by the seller that were transferred to WPD Midlands in connection with the acquisition. A cross indemnity has been received from the seller on the tax issue. The maximum exposure and expiration of these indemnifications cannot be estimated because the maximum potential liability is not capped and the expiration date is not specified in the transaction documents.

(b) Indemnification to the liquidators and certain others for existing liabilities or expenses or liabilities arising during the liquidation process. The indemnifications are limited to distributions made from the subsidiary to its parent either prior or subsequent to liquidation or 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 where the agreements provide for specific limits.

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 or 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.

(c) Relates to certain obligations of discontinued or modified electric associations that were guaranteed at the time of privatization by the participating members. Costs are allocated to the members and can be reallocated if an existing member becomes insolvent. At December 31, 2013, WPD has recorded an estimated discounted liability 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, and as a result, the exposure has been estimated.

(d) 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

(e) Indemnifications are governed by the specific sales agreement and include breach of the representations, warranties and covenants, and liabilities for certain other matters. PPL Energy Supply's maximum exposure with respect to certain indemnifications and the expiration of the indemnifications cannot be estimated because the maximum potential liability is not capped by the transaction documents and the expiration date is based on the applicable statute of limitations. The exposure and expiration date noted is based on those cases in which the agreements provide for specific limits.

(f) Relates to a guarantee of one-third of the divested entity's debt. The purchaser provided a cross-indemnity, secured by a lien on the purchaser's stock of the divested entity. The exposure noted reflects principal only.

(g) A third party logistics firm provides inventory procurement and fulfillment services. The logistics firm has title to the inventory, however, upon termination of the contracts, PPL Electric has guaranteed to purchase any remaining inventory that has not been used or sold.

(h) 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 government fines and penalties fall outside the cumulative cap. LKE has contested the applicability of the indemnification requirement relating to one matter presented by a counterparty under this guarantee. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. In May 2012, LKE's indemnitee received an arbitration panel's decision affecting this matter, which granted LKE's indemnitee certain rights of first refusal to purchase excess power at a market-based price rather than at an absolute fixed price. In January 2013, LKE's indemnitee commenced a proceeding in the Kentucky Court of Appeals appealing the December 2012 order of the Henderson Circuit Court, confirming the arbitration award. A decision in the appellate matter may occur during 2014. LKE believes its indemnification obligations in this matter remain subject to various uncertainties, including potential for additional legal challenges regarding the arbitration decision as well as future prices, availability and demand for the subject excess power. LKE continues to evaluate various legal and commercial options with respect to this indemnification matter. The ultimate outcomes of the WKE termination-related indemnifications cannot be predicted at this time. Additionally, LKE has indemnified various third parties related to historical obligations for other divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum exposures range from being capped at the sale price to no specified maximum; however, LKE is not aware of formal claims under such indemnities made by any party at this time. LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. In the second quarter of 2012, LKE adjusted its estimated liability for certain of these indemnifications by $9 million ($5 million after-tax), which is reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income. The adjustment was recorded in the Kentucky Regulated segment for PPL. LKE cannot predict the ultimate outcomes of such indemnification circumstances, but does not currently expect such outcomes to result in significant losses above the amounts recorded.

(i) Pursuant to the OVEC power purchase contract, LG&E and KU are obligated to pay for their share of OVEC's excess debt service, post-retirement and decommissioning costs, as well as any shortfall from amounts currently included within a demand charge designed to cover these costs over the term of the contract. LKE's proportionate share of OVEC's outstanding debt was $129 million at December 31, 2013, consisting of LG&E's share of $89 million and KU's share of $40 million. The maximum exposure and the expiration date of these potential obligations are not presently determinable. See "Energy Purchases Commitments" above for additional information on the OVEC power purchase contract.

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 provides maximum aggregate coverage of $225 million. This insurance may be applicable to obligations under certain of these contractual arrangements.