$250,000,000 aggregate principal amount of its 1.625% First Mortgage Bonds due 2015 and
$285,000,000 aggregate principal amount of its 5.125% First Mortgage Bonds due 2040,
each of which have been registered under the Securities Act of 1933, as amended,
for any and all of its outstanding
1.625% First Mortgage Bonds due 2015 and 5.125% First Mortgage Bonds due 2040,
respectively

We are conducting the Offers to Exchange described above, or Exchange Offers, in order to provide you with an opportunity to exchange your unregistered outstanding bonds referred to above, or Outstanding Bonds, for substantially identical bonds of the same series that have been registered under the Securities Act, which we refer to as the Exchange Bonds.

All untendered Outstanding Bonds will remain outstanding and continue to be subject to the restrictions on transfer set forth in the Outstanding Bonds and in the indenture governing the Outstanding Bonds. In general, the Outstanding Bonds may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the Exchange Offers, we do not currently anticipate that we will register the Outstanding Bonds under the Securities Act.

Each broker-dealer that receives Exchange Bonds for its own account in the Exchange Offers must acknowledge that it will deliver a prospectus in connection with any resale of those Exchange Bonds. The letter of transmittal states that by so acknowledging and delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Bonds received in exchange for Outstanding Bonds where the broker-dealer acquired such Outstanding Bonds as a result of market-making or other trading activities. We have agreed that, for a period of 180 days after the Expiration Date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

See "Risk Factors" beginning on page 11 for a discussion of certain risks that you should consider before participating in the Exchange Offers.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the Exchange Bonds to be distributed in the Exchange Offers or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

In making your investment decision, you should rely only on the information contained in or incorporated by reference into this prospectus. We have not authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer of the Exchange Bonds in any jurisdiction where the offer thereof is not permitted. The information contained in this prospectus speaks only as of the date of this prospectus.

References to the "Company," "we," "us" and "our" in this prospectus are references to Louisville Gas and Electric Company.

This summary highlights certain information concerning the Company, the Exchange Offers and the Exchange Bonds that may be contained elsewhere in this prospectus. This summary is not complete and does not contain all the information that may be important to you. You should read this prospectus in its entirety before making an investment decision.

Louisville Gas and Electric Company, incorporated in Kentucky in 1913, is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy and the storage, distribution and sale of natural gas. We provide electric service to approximately 395,000 customers in Louisville and adjacent areas in Kentucky covering approximately 700 square miles in nine counties. Natural gas service is provided to approximately 320,000 customers in our electric service area and eight additional counties in Kentucky. During 2010, approximately 95% of the electricity we generated was produced by our coal-fired electric generating stations, all equipped with systems to reduce SO2.emissions. The remainder was generated by natural gas and oil fueled combustion turbines, or CTs, and a hydroelectric power plant. Underground natural gas storage fields help us provide economical and reliable natural gas service to customers.

Our principal executive offices are located at 220 West Main Street, Louisville, Kentucky 40202 (Telephone number (502) 627-2000).

In January 2010, we filed an application with the Kentucky Public Service Commission, or the Kentucky Commission, requesting an increase in electric base rates of approximately 12%, or $95 million annually, and natural gas base rates of approximately 8%, or $23 million annually. A number of intervenors entered the rate case, including the office of the Attorney General of Kentucky, certain representatives of industrial and low-income groups and other third parties, and submitted filings challenging our requested rate increases, in whole or in part. In June 2010, we and all of the intervenors except for the Kentucky Attorney General agreed to stipulations providing for an increase in our electric base rates of $74 million annually and natural gas base rates of $17 million annually, and jointly filed a request with the Kentucky Commission to approve such settlement. An order in the proceeding was issued in July 2010, approving all provisions in the stipulation, including a return on equity range of 9.75-10.75%. The new rates became effective on August 1, 2010.

On November 1, 2010, we became an indirect wholly owned subsidiary of PPL Corporation when PPL acquired all of the outstanding limited liability company interests in our direct parent, LG&E and KU Energy LLC, or Parent (formerly E.ON U.S. LLC), from E.ON US Investments Corp. Our Parent, a Kentucky limited liability company, also owns our affiliate, Kentucky Utilities Company, or KU, a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy in Kentucky, Virginia and Tennessee. Following the acquisition, our business has not changed and we and KU are continuing as subsidiaries of our Parent, which is now an intermediary holding company in

the PPL group of companies. An abridged structure of the PPL group of companies, including, us, is shown below:

PPL, incorporated in 1994 and headquartered in Allentown, Pennsylvania, is an energy and utility holding company. Through its subsidiaries, PPL Corporation owns or controls about 19,000 megawatts, or Mw, of generating capacity in the United States, sells energy in key U.S. markets, and delivers electricity and natural gas to about 10 million customers in the United States and the United Kingdom.

Neither PPL nor any of its other subsidiaries, including our Parent or KU, will be obligated to make payments on, or provide any credit support for, the Exchange Bonds.

In September 2010, the Kentucky Commission approved a settlement agreement among PPL, joint applicants and all of the intervening parties to PPL's joint application to the Kentucky Commission for approval of its acquisition of ownership and control of our Parent, the Company and KU. In the settlement, the parties agreed that we and KU would commit that no base rate increases would take effect before January 1, 2013. Our rate increase that took effect on August 1, 2010 (See "Business—Rates and Regulation") will not be impacted by the settlement. Under the terms of the settlement, we retain the right to seek approval for the deferral of "extraordinary and uncontrollable costs." Interim rate adjustments will continue to be permissible during that period for existing fuel, environmental and demand-side management, or DSM, cost trackers. The agreement also substituted an acquisition savings shared deferral mechanism for the requirement that we file a synergies plan with the Kentucky Commission. This mechanism, which will be in place until the earlier of five years or the first day of the year in which a base rate increase becomes effective, permits us to earn up to a 10.75% return on equity. Any earnings above a 10.75% return on equity will be shared with customers on a 50%/50% basis. The Kentucky Commission order contained a number of other commitments with regards to operations, workforce, community involvement and other matters.

In October 2010, the Federal Energy Regulatory Commission, or FERC, approved a September 2010 settlement agreement among the Company, KU, other applicants and protesting parties, and such protests have been withdrawn. The settlement agreement includes various conditional commitments, such as a continuation of certain existing undertakings with protesters in prior cases, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that we have agreed to not seek the same transaction-related cost from retail customers and agreements to coordinate with protesters in certain open or on-going matters.

In November 2010, we issued the Outstanding Bonds in transactions not subject to the registration requirements of the Securities Act of 1933, as amended, or Securities Act. The term "2015 Exchange Bonds" refers to the 1.625% First Mortgage Bonds due 2015 and the term "2040 Exchange Bonds" refers to the 5.125% First Mortgage Bonds due 2040, each as registered under the Securities Act, and all of which collectively are referred to as the "Exchange Bonds." The term "Bonds" collectively refers to the Outstanding Bonds and the Exchange Bonds.


General		In connection with the issuance of the Outstanding Bonds, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, among other things, to deliver this prospectus to you and to use commercially reasonable efforts to complete the Exchange Offers within 315 days after the date of original issuance of the Outstanding Bonds. You are entitled to exchange in the Exchange Offers your Outstanding Bonds for the respective series of Exchange Bonds that are identical in all material respects to the Outstanding Bonds except:
		• the Exchange Bonds have been registered under the Securities Act and, therefore, will not be subject to the restrictions on transfer applicable to the Outstanding Bonds (except as described in "The Exchange Offers—Resale of Exchange Bonds" and "Description of the Exchange Bonds—Form; Transfers; Exchanges");
		• the Exchange Bonds are not entitled to any registration rights which are applicable to the Outstanding Bonds under the registration rights agreement, including any rights to liquidated damages for failure to comply with the registration rights agreement; and
		• the Exchange Bonds will bear different CUSIP numbers.
The Exchange Offers		We are offering to exchange:
		• $250,000,000 aggregate principal amount of 1.625% First Mortgage Bonds due 2015 that have been registered under the Securities Act for any and all of our existing 1.625% First Mortgage Bonds due 2015;
		• $285,000,000 aggregate principal amount of 5.125% First Mortgage Bonds due 2040 that have been registered under the Securities Act for any and all of our existing 5.125% First Mortgage Bonds due 2040 and
		You may only exchange Outstanding Bonds in minimum denominations of $2,000 and in multiples of $1,000 in excess thereof. Any untendered Outstanding Bonds must also be in a minimum denomination of $2,000.


Resale		Based on an interpretation by the staff of the Securities and Exchange Commission, or SEC, set forth in no-action letters issued to third parties, we believe that the Exchange Bonds issued pursuant to the Exchange Offers in exchange for the Outstanding Bonds may be offered for resale, resold and otherwise transferred by you (unless you are our "affiliate" within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:
		• you are acquiring the Exchange Bonds in the ordinary course of your business; and
		• you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the Exchange Bonds.
		Any holder of Outstanding Bonds who:
		• is our affiliate;
		• does not acquire Exchange Bonds in the ordinary course of its business; or
		• tenders its Outstanding Bonds in the Exchange Offers with the intention to participate, or for the purpose of participating, in a distribution of Exchange Bonds
		cannot rely on the position of the staff of the SEC enunciated in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in Shearman & Sterling (available July 2, 1993), or similar no-action letters and, in the absence of an exemption therefrom, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the Exchange Bonds.
		If you are a broker-dealer and receive Exchange Bonds for your own account in exchange for Outstanding Bonds that you acquired as a result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the Exchange Bonds and that you are not our affiliate and did not purchase your Outstanding Bonds from us or any of our affiliates. See "Plan of Distribution."


		Our belief that the Exchange Bonds may be offered for resale without compliance with the registration or prospectus delivery provisions of the Securities Act is based on interpretations of the SEC for other exchange offers that the SEC expressed in some of its no-action letters to other issuers in exchange offers like ours. We have not sought a no-action letter in connection with the Exchange Offers, and we cannot guarantee that the SEC would make a similar decision about our Exchange Offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any Exchange Bond issued to you in the Exchange Offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. We are not indemnifying you for any such liability.
Expiration Date		The Exchange Offers will expire at 5:00 p.m., New York City time, on June 30, 2011, unless extended by us. We do not currently intend to extend the Expiration Date.
Withdrawal		You may withdraw the tender of your Outstanding Bonds at any time prior to the expiration of the Exchange Offers. We will return to you any of your Outstanding Bonds that are not accepted for any reason for exchange, without expense to you, promptly after the expiration or termination of the Exchange Offers.
Conditions to the Exchange Offers		Each Exchange Offer is subject to customary conditions. We reserve the right to waive any defects, irregularities or conditions to exchange as to particular Outstanding Bonds. See "The Exchange Offers—Conditions to the Exchange Offers."
Procedures for Tendering Outstanding Bonds		If you wish to participate in any of the Exchange Offers, you must either:
		• complete, sign and date the applicable accompanying letter of transmittal, or a facsimile of the letter of transmittal, in accordance with the instructions contained in this prospectus and the letter of transmittal, and mail or deliver such letter of transmittal or facsimile thereof, together with the Outstanding Bonds to be exchanged for Exchange Bonds, to the exchange agent at the address set forth on the cover page of the letter of transmittal; or
		• if you hold Outstanding Bonds through The Depository Trust Company, or DTC, comply with DTC's Automated Tender Offer Program procedures described in this prospectus, by which you will agree to be bound by the letter of transmittal.


		By signing, or agreeing to be bound by, the letter of transmittal, you will represent to us that, among other things:
		• any Exchange Bonds received by you will be acquired in the ordinary course of your business;
		• you have no arrangements or understanding with any person to participate in the distribution of the Exchange Bonds within the meaning of the Securities Act;
		• you are not engaged in, and do not intend to engage in, the distribution of the Exchange Bonds;
		• you are not an "affiliate," as defined in Rule 405 of the Securities Act, of the Company or, if you are an affiliate, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and
		• if you are a broker-dealer, you will receive Exchange Bonds for your own account in exchange for Outstanding Bonds that were acquired as a result of market-making activities or other trading activities, and you will deliver a prospectus in connection with any resale of such Exchange Bonds.
Special Procedures for Beneficial Owners		If you are a beneficial owner of Outstanding Bonds that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender those Outstanding Bonds in any of the Exchange Offers, you should contact the registered holder promptly and instruct the registered holder to tender those Outstanding Bonds on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Bonds, either make appropriate arrangements to register ownership of the Outstanding Bonds in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the Expiration Date.
Guaranteed Delivery Procedures		If you wish to tender your Outstanding Bonds and your Outstanding Bonds are not immediately available, or you cannot deliver your Outstanding Bonds, the letter of transmittal or any other required documents, or you cannot comply with the procedures under DTC's Automated Tender Offer Program for transfer of book-entry interests prior to the Expiration Date, you must tender your Outstanding Bonds according to the guaranteed delivery procedures set forth in this prospectus under "The Exchange Offers—Guaranteed Delivery Procedures."


Effect on Holders of Outstanding Bonds		As a result of the making of, and upon acceptance for exchange of all validly tendered Outstanding Bonds pursuant to the terms of, the Exchange Offers, we will have fulfilled a covenant under the registration rights agreement. Accordingly, we will not be required to pay liquidated damages on the Outstanding Bonds under the circumstances described in the registration rights agreement. If you do not tender your Outstanding Bonds in any of the Exchange Offers, you will continue to be entitled to all the rights and limitations applicable to the Outstanding Bonds as set forth in the Indenture (as defined below), except we will not have any further obligation to you to provide for the exchange and registration of untendered Outstanding Bonds under the registration rights agreement. To the extent that Outstanding Bonds are tendered and accepted in the Exchange Offers, the trading market for Outstanding Bonds that are not so tendered and accepted could be adversely affected.
Consequences of Failure to Exchange		All untendered Outstanding Bonds will remain outstanding and continue to be subject to the restrictions on transfer set forth in the Outstanding Bonds and in the Indenture. In general, the Outstanding Bonds may not be offered or sold unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the Exchange Offers, we do not currently anticipate that we will register the Outstanding Bonds under the Securities Act.
United States Federal Income Tax Consequences		The exchange of Outstanding Bonds in the Exchange Offers will not be a taxable event for US federal income tax purposes. See "Material U.S. Federal Income Tax Consequences."
Use of Proceeds		We will not receive any proceeds from the issuance of the Exchange Bonds in the Exchange Offers. See "Use of Proceeds."
Exchange Agent		The Bank of New York Mellon is the exchange agent for the Exchange Offers. Any questions and requests for assistance with respect to accepting or withdrawing from the Exchange Offers, requests for additional copies of this prospectus or of the letter of transmittal and requests for the notice of guaranteed delivery should be directed to the exchange agent. The address and telephone number of the exchange agent are set forth in the section captioned "The Exchange Offers—Exchange Agent."

The summary below describes the principal terms of the Exchange Bonds. Certain of the terms and conditions described below are subject to important limitations and exceptions. The "Description of the Exchange Bonds" section of this prospectus contains more detailed descriptions of the terms and conditions of the Outstanding Bonds and Exchange Bonds. The Exchange Bonds will have terms identical in all material respects to the respective series of Outstanding Bonds, except that the Exchange Bonds will not contain certain terms with respect to transfer restrictions, registration rights and liquidated damages for failure to observe certain obligations in the registration rights agreement.


Issuer		Louisville Gas and Electric Company, a Kentucky corporation.
Securities Offered		$250,000,000 of 2015 Exchange Bonds
		$285,000,000 of 2040 Exchange Bonds
Maturity Date		The 2015 Exchange Bonds will mature on November 15, 2015.
		The 2040 Exchange Bonds will mature on November 15, 2040.
Interest Rate and Payment Dates		The 2015 Exchange Bonds will bear interest at the rate of 1.625% per annum, payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2011.
		The 2040 Exchange Bonds will bear interest at the rate of 5.125% per annum, payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2011.
		Interest will accrue on the Exchange Bonds of each series from May 15, 2011, the most recent interest payment date to which interest has been paid on the Outstanding Bonds surrendered in the Exchange Offers.
Optional Redemption		We may redeem the Exchange Bonds at our option, in whole at any time or in part from time to time, on not less than 30 nor more than 60 days' notice, at the redemption prices described under "Description of the Exchange Bonds—Redemption."
		We may redeem, in whole or in part, Exchange Bonds of any or all series.
Ranking		Each series of Exchange Bonds will be our senior secured indebtedness and will rank equally in right of payment with our existing and future first mortgage bonds issued under our Mortgage.
Security		Each series of Exchange Bonds will be secured, equally and ratably, by the lien of the Mortgage, which constitutes a first mortgage lien on substantially all of our real and tangible personal property located in Kentucky and used in the generation, transmission and distribution of electricity (other than property duly released from the lien of the Mortgage in accordance with the provisions thereof and certain other excepted property, and subject to certain Permitted Liens), as described under "Description of the Bonds—Security; Lien of the Mortgage."


Events of Default		For a discussion of events that will permit acceleration of the payment of the principal of and accrued interest on the Exchange Bonds, see "Description of the Exchange Bonds—Events of Default."
Further Issuances		Subject to compliance with certain issuance conditions contained in the Mortgage, we may, without the consent of the holders of a series of the Exchange Bonds, increase the principal amount of the series and issue additional bonds of such series having the same ranking, interest rate, maturity and other terms (other than the date of issuance and, in some circumstances, the initial interest accrual date and initial interest payment date) as the Exchange Bonds. Any such additional bonds would, together with the existing Exchange Bonds of such series, constitute a single series of securities under the Mortgage and may be treated as a single class for all purposes under the Mortgage, including, without limitation, voting, waivers and amendments.
Company Obligations		Our obligations to pay the principal of, premium, if any, and interest on the Exchange Bonds are solely obligations of the Company and none of our direct or indirect parent companies nor any of their subsidiaries or affiliates will guarantee or provide any credit support for our obligations on the Exchange Bonds.
Denominations		Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Form of Bonds		The Exchange Bonds will be issued in fully registered book-entry form and each series of Exchange Bonds will be represented by one or more global certificates, which will be deposited with or on behalf of DTC and registered in the name of DTC's nominee. Beneficial interests in global certificates will be shown on, and transfers thereof will be effected only through, records maintained by DTC and its direct and indirect participants, and your interest in any global certificate may not be exchanged for certificated bonds, except in limited circumstances described herein. See "Description of the Exchange Bonds—Book-Entry Only Issuance—The Depository Trust Company."
Trustee		The Bank of New York Mellon


Absence of Established Market for the Exchange Bonds		We do not plan to have the Exchange Bonds listed on any securities exchange or included in any automated quotation system. There is no existing trading market for the Exchange Bonds. If no active trading market develops, you may not be able to resell your Exchange Bonds at their fair market value or at all. Future trading prices of the Exchange Bonds will depend on many factors including, among other things, prevailing interest rates, our operating results and the market for similar securities. No assurance can be given as to the liquidity of or trading market for the Exchange Bonds.
Risk Factors		You should refer to the section entitled "Risk Factors" beginning on page 11 for a discussion of material risks you should carefully consider before deciding to exchange your Outstanding Bonds.

An investment in the Bonds, including a decision to tender your Outstanding Bonds in the Exchange Offers, involves a number of risks. Risks described below should be carefully considered together with the other information included in this prospectus. Any of the events or circumstances described as risks below could result in a significant or material adverse effect on our business, results of operations, cash flows or financial condition, and a corresponding decline in the market price of, or our ability to repay, the Bonds. The risks and uncertainties described below may not be the only risks and uncertainties that we face. Additional risks and uncertainties not currently known may also result in a significant or material adverse effect on our business, results of operations, cash flow or financial condition.

The following risks apply to the Outstanding Bonds and will apply equally to the Exchange Bonds.

Our business is subject to significant and complex governmental regulation.

Various federal and state entities, including but not limited to, the FERC and the Kentucky Commission, regulate many aspects of our utility operations, including the following:

Such regulations or changes thereto may subject us to higher operating costs or increased capital expenditures and failure to comply could result in sanctions or possible penalties. In any rate-setting proceedings, federal or state agencies, intervenors and other permitted parties may challenge our rate requests, and ultimately reduce, alter or limit the rates we seek.

Our profitability is highly dependent on our ability to recover the costs of providing energy and utility services to our customers and earn an adequate return on our capital investments. We currently provide services to our retail customers at rates approved by one or more federal or state regulatory commissions, including those commissions referred to above. While these rates are generally regulated based on an analysis of their costs incurred in a base year, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commissions will consider all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs or an adequate return on our capital investments. If our costs are not adequately recovered through rates, it could have an adverse affect on our business, results of operations, cash flows or financial condition.

In connection with the PPL acquisition, we have agreed, subject to certain limited exceptions such as fuel and environmental cost recoveries, that no base rate increase would take effect for our retail

customers before January 1, 2013. See "Summary—Recent Developments—PPL Acquisition Approvals."

Our transmission and interstate market activities, as well as other aspects of our business, are subject to significant FERC regulation.

Our business is subject to extensive regulation by the FERC covering matters including rates charged to transmission users, market-based or cost-based rates applicable to wholesale customers; interstate power market structure; construction and operation of transmission facilities; mandatory reliability standards; standards of conduct and affiliate restrictions and other matters. Existing FERC regulation, changes thereto or issuances of new rules or situations of non-compliance, including, but not limited to, the areas of market-based tariff authority, revenue sufficiency guarantee resettlements in the Midwest Independent Transmission System Operator, Inc. market, mandatory reliability standards and natural gas transportation regulation can affect our earnings, operations or other activities.

Changes in transmission and wholesale power market structures could increase costs or reduce revenues.

Wholesale sales fluctuate with regional demand, fuel prices and contracted capacity. Changes to transmission and wholesale power market structures and prices may occur in the future, are not estimable and may result in unforeseen effects on energy purchases and sales, transmission and related costs or revenues. These can include commercial or regulatory changes affecting power pools, exchanges or markets in which we participate.

We undertake significant capital projects and these activities are subject to unforeseen costs, delays or failures, as well as risk of inadequate recovery of resulting costs.

Our business is capital intensive and requires significant investments in energy generation and distribution and other infrastructure projects, such as projects for environmental compliance. The completion of these projects without delays or cost overruns is subject to risks in many areas, including the following:

Failure to complete our capital projects on schedule or on budget, or at all, could adversely affect our financial performance, operations and future growth.

Our costs of compliance with, and liabilities under, environmental laws are significant and are subject to continual changes.

Extensive federal, state and local environmental laws and regulations are applicable to our air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be

material. In addition, our costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of our key suppliers, or customers, such as coal producers, industrial power users, etc., and may impact the costs of their products or their demand for our services.

We are subject to operational and financial risks regarding certain on-going developments concerning environmental regulation.

A number of regulatory initiatives have been implemented or are under development which could have the effect of significantly increasing the environmental regulation or operational or compliance costs related to a number of emissions or operating activities which are associated with the combustion of coal as occurs at our generating stations. Such developments could include potential new or revised federal or state legislation or regulation regarding emissions of NOx, SO₂, mercury and other particulates generally and regarding storage of coal combustion byproducts. Additional regulatory initiatives may occur in other areas involving our operations, including revision of limitations on water discharge or intake activities or increased standards relating to polychlorinated biphenyl, or PCB, usage. Compliance with any new laws or regulations in these matters could result in significant changes to our operations, significant capital expenditures or significant increases in the cost of conducting business.

Our operating results are affected by weather conditions, including storms and seasonal temperature variations, as well as by significant man-made or accidental disturbances, including terrorism or natural disasters.

These weather or other factors can significantly affect our finances or operations by changing demand levels; causing outages; damaging infrastructure or requiring significant repair costs; affecting capital markets and general economic conditions or impacting future growth.

We are subject to operational and financial risks regarding potential developments concerning global climate change.

Various regulatory and industry initiatives have been implemented or are under development to regulate or otherwise reduce emissions of greenhouse gases, or GHGs, which are emitted from the combustion of fossil fuels such as coal and natural gas, as occurs at our generating stations. Such developments could include potential federal or state legislation or regulations limiting GHG emissions; establishing costs or charges on GHG emissions or on fuels relating to such emissions; requiring GHG capture and sequestration or other mitigation measures; establishing renewable portfolio standards or generation fleet-diversification requirements to address GHG emissions; promoting energy efficiency and conservation; mandating changes in transmission grid construction, operation or pricing to accommodate GHG-related initiatives; or requiring other measures. Our generation fleet is predominantly coal-fired and may be highly impacted by developments in this area. Compliance with any new laws or regulations regarding the reduction of GHG emissions could result in significant changes to our operations, significant capital expenditures and a significant increase in our cost of conducting business. We may face strong competition for, or difficulty in obtaining, required GHG-compliance related goods and services, including construction services, emissions allowances and financing, insurance and other inputs relating thereto. Increases in our costs or prices of producing or selling electric power due to GHG-related developments could materially reduce or otherwise affect the demand, revenue or margin levels applicable to our power, thus adversely affecting our financial condition or results of operations.

We are subject to physical, market and economic risks relating to potential effects of climate change.

Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation changes, such as warming, floods or drought. These changes may affect farm and agriculturally-dependent businesses and activities, which are an important part of Kentucky's economy, and thus may impact consumer demand for electric power. Temperature increases could result in increased overall electricity volumes or peaks and precipitation changes could result in droughts reducing the availability of water for plant cooling operations or floods interfering with facility operations. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Conversely, climate change could have a number of potential impacts tending to reduce demand. Changes may entail more frequent or more intense storm activity, which, if severe, could temporarily disrupt regional economic conditions and adversely affect electricity demand levels. As discussed in other risk factors, storm outages and damage often directly decrease revenues or increase expenses, due to reduced usage and higher restoration charges, respectively. GHG regulation could increase the cost of electric power, particularly power generated by fossil fuels, and such increases could have a depressive effect on the regional economy. Reduced economic and consumer activity in our service area both in general and specific to certain industries and consumers accustomed to previously low-cost power, could reduce demand for our electricity. Also, demand for our services could be similarly lowered should consumers' preferences or market factors move toward favoring energy efficiency, low-carbon power sources or reduced electric usage generally.

Our business is subject to risks associated with local, national and worldwide economic conditions.

The consequences of prolonged recessionary conditions may include a lower level of economic activity and uncertainty or volatility regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, unfavorable changes in energy and commodity prices, and slower customer growth, which may adversely affect our future revenues and growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital. A deterioration of economic conditions may lead to decreased production by our industrial customers and, therefore, lower consumption of electricity. Decreased economic activity may also lead to fewer commercial and industrial customers and increased unemployment, which may in turn impact residential customers' ability to pay. Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure. Changes in global demand may impact the ability to acquire sufficient supplies and the cost of those commodities may be higher than expected.

Our business is concentrated in Kentucky. Local and regional economic conditions, such as population growth, industrial growth, expansion and economic development or employment levels, as well as the operational or financial performance of major industries or customers, can affect the demand for energy and our results of operations. Significant industries and activities in our service area include airport and logistics activities; automotive; chemical and rubber processing; educational institutions; health care facilities; metal fabrication and water and sewer utilities. Any significant downturn in these industries or activities or in local and regional economic conditions in our service area may adversely affect the demand for electricity in our service area.

We are subject to operational risks relating to our generating plants, transmission facilities, distribution equipment, information technology systems and other assets and activities.

Operation of power plants, transmission and distribution facilities, information technology systems and other assets and activities subjects us to many risks, including the breakdown or failure of equipment; accidents; security breaches, viruses or outages affecting information technology systems;

labor disputes; obsolescence; delivery/transportation problems and disruptions of fuel supply and performance below expected levels. Occurrences of these events may impact our ability to conduct our business efficiently or lead to increased costs, expenses or losses.

Although we maintain customary insurance coverage for certain of these risks common to utilities, we do not have insurance covering our transmission and distribution systems, other than substations, because we have found the cost of such insurance to be prohibitive. If we are unable to recover the costs incurred in restoring our transmission and distribution properties following damage as a result of ice storms, tornados or other natural disasters or to recover the costs of other liabilities arising from the risks of our business, through a change in our rates or otherwise, or if such recovery is not received on a timely basis, we may not be able to restore losses or damages to our properties without an adverse effect on our financial condition, results of operations or our reputation.

We are subject to liability risks relating to our generating, transmission, distribution and retail businesses.

The conduct of our physical and commercial operations subjects us to many risks, including risks of potential physical injury, property damage or other financial affects, caused to or caused by employees, customers, contractors, vendors, contractual or financial counterparties and other third-parties.

We could be negatively affected by rising interest rates, downgrades to our bond credit ratings or other negative developments in our ability to access capital markets.

In the ordinary course of business, we are reliant upon adequate long-term and short-term financing means to fund our significant capital expenditures, debt interest or maturities and operating needs. As a capital-intensive business, we are sensitive to developments in interest rate levels; credit rating considerations; insurance, security or collateral requirements; market liquidity and credit availability and refinancing steps necessary or advisable to respond to credit market changes. Changes in these conditions could result in increased costs and decreased liquidity available to the Company.

We are subject to commodity price risk and counterparty credit risk associated with the energy business.

General market or pricing developments or failures by counterparties to perform their obligations relating to energy, fuels, other commodities, goods, services or payments could result in potential increased costs to the Company. We have regulatory cost recovery mechanisms in place to mitigate negative fluctuations in commodity supply prices, and credit policies to limit our exposure to counterparty credit, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations or failure of counterparties with whom we contract to perform their contractual obligations.

We are subject to risks associated with defined benefit retirement plans, health care plans, wages and other employee-related matters.

We sponsor pension and postretirement benefit plans for our employees. Risks with respect to these plans include adverse developments in legislation or regulation, future costs or funding levels, returns on investments, market fluctuations, interest rates and actuarial matters. Changes in health care rules, market practices or cost structures can affect our current or future funding requirements or liabilities. Without sustained growth in our investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. We are also subject to risks related to changing wage levels, whether related to collective bargaining agreements or employment market conditions, ability to attract and retain key personnel and changing costs of providing health care benefits.

We are subject to risks associated with federal and state tax regulations.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, sales and use and employment-related taxes. We also estimate our ability to utilize tax benefits and tax credits. Due to the revenue needs of the state and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced or the effect on the Company of any such changes. If enacted, any changes could increase tax expense and could have a negative impact on our results of operations and cash flows.

There may be adverse consequences if you do not exchange your Outstanding Bonds.

If you do not exchange your Outstanding Bonds for Exchange Bonds in the Exchange Offers, you will continue to be subject to restrictions on transfer of your Outstanding Bonds as set forth in the offering memorandum distributed in connection with the private offering of the Outstanding Bonds. In general, the Outstanding Bonds may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the Outstanding Bonds under the Securities Act. You should refer to "Prospectus Summary—The Exchange Offers" and "The Exchange Offers" for information about how to tender your Outstanding Bonds.

The tender of Outstanding Bonds under the Exchange Offers will reduce the outstanding amount of the Outstanding Bonds, which may have an adverse effect upon, and increase the volatility of, the market prices of the Outstanding Bonds due to a reduction in liquidity.

Your ability to transfer the Exchange Bonds may be limited if there is no active trading market, and there is no assurance that any active trading market will develop for the Exchange Bonds.

We are offering the Exchange Bonds to the holders of the Outstanding Bonds. We do not intend to list the Exchange Bonds on any securities exchange. There is currently no established market for the Exchange Bonds. If no active trading market develops, you may not be able to resell your Exchange Bonds at their fair market value or at all. Future trading prices of the Exchange Bonds will depend on many factors including, among other things, prevailing interest rates, our operating results and the market for similar securities. No assurance can be given as to the liquidity of or trading market for the Exchange Bonds.

Certain persons who participate in the Exchange Offers must deliver a prospectus in connection with resales of the Exchange Bonds.

Based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (available May 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (available June 5, 1991) and Shearman & Sterling, SEC no-action letter (available July 2, 1993), we believe that you may offer for resale, resell or otherwise transfer the Exchange Bonds without compliance with the registration and prospectus delivery requirements of the Securities Act. We cannot guarantee that the SEC would make a similar decision about our Exchange Offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any Exchange Bond issued to you in the Exchange Offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. Additionally, in some instances described in this prospectus under "Plan of Distribution," certain holders of Exchange Bonds will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the Exchange Bonds. If such a

holder transfers any Exchange Bonds without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, such a holder may incur liability under the Securities Act. We do not and will not assume, or indemnify such a holder against, this liability.

The following risks apply to the Outstanding Bonds and will apply equally to the Exchange Bonds.

If the ratings of the Bonds are lowered or withdrawn, the market value of the Bonds could decrease.

A rating is not a recommendation to purchase, hold or sell the Bonds, inasmuch as the rating does not comment as to market price or suitability for a particular investor. The ratings of the Bonds address the rating agencies' views as to the likelihood of the timely payment of interest and the ultimate repayment of principal of the Bonds pursuant to their respective terms. There is no assurance that a rating will remain for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if in their judgment circumstances in the future so warrant. In the event that any of the ratings initially assigned to the Bonds is subsequently lowered or withdrawn for any reason, the market price of the Bonds may be adversely affected.

We use forward-looking statements in this prospectus. Statements that are not historical facts are forward-looking statements, and are based on beliefs and assumptions of our management, and on information currently available to management. Forward-looking statements include statements preceded by, followed by or using such words as "believe," "expect," "anticipate," "plan," "estimate" or similar expressions. Actual results may materially differ from those implied by forward-looking statements due to known and unknown risks and uncertainties. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

In light of these risks and uncertainties, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. For additional details regarding these and other risks and uncertainties, see "Risk Factors" on page 11 of this prospectus.

We will not receive any cash proceeds from the issuance of the Exchange Bonds pursuant to the Exchange Offers. In consideration for issuing the Exchange Bonds as contemplated in this prospectus, we will receive in exchange a like principal amount of Outstanding Bonds, the terms of which are identical in all material respects to the Exchange Bonds of the related series, except that the Exchange Bonds will not contain terms with respect to transfer restrictions, registration rights and liquidated damages for failure to observe certain obligations in the registration rights agreement. The Outstanding Bonds surrendered in exchange for the Exchange Bonds will be retired and cancelled, and will not be reissued. Accordingly, the issuance of the Exchange Bonds will not result in any increase in our outstanding debt or the receipt of any additional proceeds.

The following table sets forth our capitalization as of March 31, 2011. You should read the data set forth below in conjunction with "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," our Financial Statements as of December 31, 2010 and 2009 and for the Years Ended December 31, 2010, 2009 and 2008 included elsewhere in this prospectus (the "2010 Annual Financial Statements") and our Unaudited Condensed Financial Statements as of March 31, 2011 and December 31, 2010, and for the Three Months Ended March 31, 2011 and 2010 included elsewhere in this prospectus ("First Quarter Financial Statements").

The Outstanding Bonds that are surrendered in exchange for the Exchange Bonds will be retired and cancelled and cannot be reissued. As a result, the issuance of the Exchange Bonds will not result in any change in our capitalization.

The selected financial data presented below for the five fiscal years ended December 31, 2010, and as of December 31 for each of those years, have been derived from our audited financial statements. Our audited financial statements for the three fiscal years ended December 31, 2010, and as of December 31, 2010 for each of those years, are included in this prospectus. The selected financial data for the three months ended March 31, 2011 and 2010 and as of March 31, 2011 and 2010 are derived from our unaudited financial statements included in this prospectus. Historical results are not necessarily indicative of future results. Our financial statements and related financial and operating data include the periods before and after PPL's acquisition of our Parent on November 1, 2010, and are labeled as Predecessor or Successor. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview" for additional information.

You should read the data set forth below in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited and unaudited financial statements and related notes included elsewhere in this prospectus.

Dollars are in millions unless otherwise noted. Balance sheet date is as of the last date in the period.



		Successor		Predecessor		Successor		Predecessor
		Three Months Ended March 31, 2011		Three Months Ended March 31, 2010		November 1, 2010 through December 31, 2010		January 1, 2010 through October 31, 2010		Year Ended December 31,
		Three Months Ended March 31, 2011		Three Months Ended March 31, 2010		November 1, 2010 through December 31, 2010		January 1, 2010 through October 31, 2010		2009		2008		2007		2006
Operating revenues		$	398	$	366	$	254	$	1,057	$	1,272	$	1,468	$	1,285	$	1,338

Operating income		$	73	$	64	$	40	$	188	$	167	$	219	$	229	$	223

Net Income		$	39	$	33	$	19	$	109	$	95	$	90	$	120	$	117

Total assets		$	4,293	$	3,494	$	4,519	$	3,699	$	3,568	$	3,653	$	3,313	$	3,184

Long-term debt obligations (including amounts due within one year)		$	1,112	$	896	$	1,112	$	896	$	896	$	896	$	984	$	820

Other Financial Data:
	Ratio of Earnings to Fixed Charges(1)		6.08		5.17		4.75		4.68		3.65		3.77		4.38		4.81

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We are a regulated utility engaged in the generation, transmission, distribution and sale of electric energy and the storage, distribution and sale of natural gas in Kentucky. See "Business" for a description of the business. The rates we charge our customers require approval of the appropriate regulatory government agency. See Note 3 to our 2010 Annual Financial Statements and Note 3 to our First Quarter Financial Statements for information regarding rate cases, regulatory assets and liabilities and other regulatory matters.

The Company and its affiliate, KU, are wholly owned subsidiaries of our Parent, a Kentucky limited liability company. PPL Corporation acquired our Parent on November 1, 2010. Headquartered in Allentown, Pennsylvania, PPL is an energy and utility holding company that was incorporated in 1994. Through its subsidiaries, PPL owns or controls about 19,000 Mw of generating capacity in the U.S., sells energy in key U.S. markets and delivers electricity and natural gas to about 10 million customers in the U.S. and the U.K. Following the acquisition, both the Company and KU continue operating as subsidiaries of our Parent, which is now an intermediary holding company in the PPL group of companies. See Note 2 to our 2010 Annual Financial Statements for further information regarding the acquisition

The following discussion and analysis by management focuses on those factors that had a material effect on our results of operations and financial condition during the periods presented and should be read in connection with the financial statements and notes included elsewhere in this prospectus. The discussion also provides information with respect to our material risks and challenges and contains certain forward-looking statements that involve risk and uncertainties. See "Risk Factors" and "A Warning about Forward-Looking Statements" for further information. Specifically:

Our financial statements and related financial and operating data include the periods before and after PPL's acquisition of our Parent on November 1, 2010, and are labeled as Predecessor or Successor, as applicable. We applied push-down accounting to account for the acquisition. For accounting purposes only, push-down accounting is considered to create a new entity due to new cost basis assigned to assets, liabilities and equity as of the acquisition date. Consequently, certain results of

our operations and cash flows for the Predecessor period in 2010 and the Successor periods in 2010 are shown separately, rather than combined, in our audited financial statements.

In the "Management's Discussion and Analysis of Financial Condition and Results of Operations" of "Years Ended December 31, 2010 and 2009—Results of Operations" and "—Financial Condition," we have included disclosure of the combined Predecessor and Successor results of operations and cash flows. Such presentation is considered to be a non-GAAP disclosure. We have included such disclosure because we believe it facilitates the comparison of 2010 operating and financial performance to 2009 and 2008, and because our core operations have not changed as a result of the acquisition.

Protection of the environment is a major priority for us and a significant element of our business activities. Extensive federal, state and local environmental laws and regulations are applicable to our air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc., and may impact the costs of their products or their demand for our services.

Recent developments continue to indicate the possibility of significant climate change or GHG legislation or regulation, at the international, federal, regional or state levels. During December 2009, as part of the United Nation's Copenhagen Accord, the United States agreed to a non-binding goal to reduce GHG emissions to 17% below 2005 levels by 2020. Additionally, during 2009, the U.S. House of Representatives passed comprehensive GHG legislation, which included a number of measures to limit GHG emissions and achieve GHG emission reduction targets below 2005 levels of 3% by 2012, 17% by 2020 and 83% by 2050. Similar legislation has been considered in the U.S. Senate, but the prospects for passage remain uncertain. In late 2009, the U.S. Environmental Protection Agency, or EPA, issued a final endangerment finding relating to mobile sources of GHGs and a GHG reporting requirement beginning in 2010. In 2010, the EPA issued a final rule requiring implementation of best available control technology for GHG emissions from new or modified power plants, effective January 2011. In December 2010, the EPA announced that it intends to propose New Source Performance Standards addressing GHG emissions from new and existing power plants, with a proposed rule expected in July 2011. In 2011, legislation was introduced in both the House and Senate which seeks to bar the EPA from regulating GHG emissions under the existing authority of the Clean Air Act, but, to date, no such legislation has been enacted. Finally, a number of U.S. states, although not currently including Kentucky, have adopted GHG-reduction legislation or regulation of various sorts. The developing GHG initiatives include a number of differing structures and formats, including direct limitations on GHG sources, issuance of allowances for GHG emissions, cap-and-trade programs for such allowances, renewable or alternative generation portfolio standards and mechanisms relating to demand reduction, energy efficiency, smart-grid, transmission expansion, carbon-sequestration or other GHG-reducing

efforts. While the final terms and impacts of such initiatives cannot be estimated, we, as a primarily coal-fired utility, could be highly affected by such proceedings.

The EPA has proposed or announced that it intends to propose, and in some cases has finalized, a number of additional environmental regulations that could substantially impact utilities with coal-fired generating assets. These regulatory initiatives include revisions to the ambient air quality standards for SO2, NO2, ozone and particulate matter 2.5 microns in size or less, rules aimed at mitigating the interstate transport of SO2 and NOx, a program governing emissions of hazardous air pollutants from utility generating units, a program for the management of coal combustion residuals, revised effluent guidelines for utility generating facilities and standards for cooling water intake structures. Such requirements could potentially mandate upgrade of existing emission controls, installation of additional emission controls such as flue gas desulfurization, selective catalytic reduction, fabric filter bag houses, activated carbon injection, wet electrostatic precipitators, closure of ash ponds and retrofit of landfills, installation of cooling towers, deployment of new water treatment technologies and retirement of facilities that cannot be retrofitted on a cost effective basis.

The cost to us and the effect on our business of complying with potential GHG restrictions and other environmental regulatory initiatives will depend upon provisions of any final rules and how the rules are implemented by the EPA. Some of the design elements which may have the greatest effect on us include (a) the required levels and timing of emissions caps, discharge limits or similar standards, (b) the sources covered by such requirements, (c) transition and mitigation provisions, such as phase-in periods, free allowances or price caps, (d) the availability and pricing of relevant mitigation or control technologies, goods or services and (e) economic, market and customer reaction to electricity price and demand changes due to environmental concerns.

Ultimately, environmental matters or potential environmental matters can represent an important element of current or future potential capital requirements, future unit retirement or replacement decisions, supply and demand for electricity, operating and maintenance expenses or compliance risks. Based on prior regulatory precedent, we currently anticipate that many of such direct costs may be recoverable through rates or other regulatory mechanisms, particularly with respect to coal-related generation, but the availability, timing or completeness of such rate recovery cannot be assured. Ultimately, climate change and other environmental matters will likely increase the level of capital expenditures and operating and maintenance costs incurred by us during the next several years. With respect to National Ambient Air Quality Standards, or NAAQS, the Clean Air Transport Rule, or CATR, the utility Maximum Achievable Control Technology, or MACT, rule, and coal combustion byproducts developments, based on a preliminary analysis of proposed regulations, we may be required to consider actions such as upgrading existing emissions controls, installing additional emissions controls, upgrading byproducts disposal and storage and possible early replacement of coal-fired units. In order to comply with the coal combustion residual rules and the above referenced air rules, our capital expenditures are preliminarily estimated to be in the $2.0 to $2.5 billion range over the next ten years, although final costs may substantially vary. This estimate does not include compliance with GHG rules or contemplated water-related environmental changes including the recently proposed Section 316(b) cooling water intake rule and the expected future revisions to effluent guidelines. See "Risk Factors," Note 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements for further information.

The utility business is affected by seasonal temperatures. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally highest during the first and third quarters, and lowest in the second quarter, due to weather.

The following table summarizes the significant components of net income for 2010, 2009 and 2008 and the changes therein:



								Predecessor
					Successor			Predecessor
		Combined			Successor						Year Ended December 31,
		Combined			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010
		Year Ended December 31, 2010
		Year Ended December 31, 2010									2009		2008
Total operating revenues		$	1,311		$	254		$	1,057		$	1,272	$	1,468
Total operating expenses			1,083			214			869			1,105		1,249

	Operating income		228			40			188			167		219
Derivative gain (loss)			19			—			19			18		(37	)
Interest expense			23			7			16			17		29
	Interest expense to affiliated companies		23			1			22			27		29
Other income (expense)—net			(5	)		(3	)		(2	)		1		7

Income before income taxes			196			29			167			142		131
Income tax expense			68			10			58			47		41

	Net income	$	128		$	19		$	109		$	95	$	90

		Increase (Decrease)

		2010 vs. 2009			2009 vs. 2008
Total operating revenues		$	39		$	(196	)
Total operating expenses			(22	)		(144	)

	Operating income		61			(52	)
Derivative gain			1			55
Interest expense			6			(12	)
Interest expense to affiliated companies			(4	)		(2	)
Other income (expense)—net			(6	)		(6	)

	Income before income taxes		54			11
Income taxes			21			6

	Net income	$	33		$	5

The $97 million increase from 2009 to 2010 and the $98 million decrease from 2008 to 2009 in electric revenues were primarily due to:

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Retail sales volumes(a)	$	46		$	(33	)
Base rate price variance(b)		33			(12	)
Fuel adjustment clause, or FAC, price variance(c)		21			13
Demand revenue(d)		14			2
Merger surcredit termination in February 2009		—			14
Increased recoverable program spending billed through the DSM		3			7
Other operating revenue primarily due to late payment charges		2			4
Transmission sales		1			—
Environmental cost recovery, or ECR, price variance(e)		(7	)		7
Value delivery team process surcredit termination in August 2008		—			4
Wholesale sales(f)		(16	)		(104	)

	$	97		$	(98	)

The decrease in retail sales volumes during 2009 compared to 2008 was attributable to reduced consumption by retail customers as a result of milder weather and weakened economic conditions, in addition to significant storm outages during 2009.

(b): The increase in revenues due to the base rate price variance during 2010 compared to 2009 resulted from higher base rates effective August 1, 2010. As part of the 2010 rate case, the 2001 and 2003 ECR plans were added to rate base, which caused a portion of this increase. See Note 3 to our 2010 Annual Financial Statements for further discussion of the 2010 Kentucky rate cases.

The decrease in revenues due to the base rate price variance during 2009 compared to 2008 resulted from a reduction in base energy rates effective February 6, 2009. See Note 3 to our 2010 Annual Financial Statements for further discussion of the 2008 Kentucky rate cases.
(c): FAC revenues increased during 2010 compared to 2009 and 2009 compared to 2008 as a result of increased recoverable fuel costs billed to customers through the FAC due to higher fuel prices.
(d): Demand revenues increased during 2010 compared to 2009 as a result of higher demand rates effective August 1, 2010 and higher customer peak demand. See Note 3 to our 2010 Annual Financial Statements for further discussion of the 2010 Kentucky rate cases.

Demand revenues increased during 2009 compared to 2008 primarily as a result of higher demand rates effective February 6, 2009, partially offset by lower customer peak demand. See Note 3 to our 2010 Annual Financial Statements for further discussion of the 2008 Kentucky cases.
(e): The decrease in revenues due to the ECR price variance during 2010 compared to 2009 resulted from lower recoverable capital spending due to the 2001 and 2003 plans being removed from the ECR mechanism.

The increase in revenues due to the ECR price variance during 2009 compared to 2008 resulted from higher recoverable capital spending.
(f): The decrease in wholesale sales during 2010 compared to 2009 was primarily due to lower sales volumes to KU and third party customers and decreased revenues from financial energy swaps. Wholesale volumes decreased as a result of increased consumption by residential customers, due to increased cooling and heating degree days, increased coal-fired generation outages and higher energy usage by industrial customers as a result of improved economic conditions. Financial energy swap revenues decreased as a result of less activity from the buyback of positions in 2010 and a change in the allocation between us and KU in 2009. See Note 15 to our 2010 Annual Financial Statements for further discussion of the mutual agreement for wholesale sales and purchases between us and KU.

The decrease in wholesale sales during 2009 compared to 2008 resulted from decreased volumes to third party customers as a result of lower economic capacity, scheduled coal-fired generation outages, decreased sales to KU due to lower fuel costs, and decreased third party prices as a result of lower prices in the spot energy market. These decreases were partially offset by increased gains in energy marketing financial swaps.

The $58 million decrease from 2009 to 2010 and $98 million decrease from 2008 to 2009 in natural gas revenues were primarily due to:

(a): Retail sales volumes increased during 2010 compared to 2009 as a result of increased consumption was primarily due to colder temperatures during the first and fourth quarters of 2010 and improved economic conditions. The increase in revenues resulting from higher volumes was partially offset by a reduction in weather normalization adjustment, or WNA.

Retail sales volumes decreased during 2009 compared to 2008 as a result of milder weather and weakened economic conditions. The decrease in the volume variance in 2009 was partially offset by increased WNA revenues resulting from lower natural gas sales volumes.
(b): The increase in revenues due to the base rate price variance during 2010 compared to 2009 resulted from higher base rates effective August 1, 2010. See Note 3 for further discussion of the 2010 Kentucky rate case.

The increase in revenues due to the base rate price variance during 2009 compared to 2008 was due to the change in base rates resulting from the application of the base rate case settlement in February 2009. See Note 3 to our 2010 Annual Financial Statements for further discussion of the 2008 Kentucky rate case.

Fuel for electric generation and natural gas supply expenses comprise a large component of total operating expenses. Increases or decreases in the cost of fuel and natural gas supply are reflected in electric and natural gas retail rates through the GSC and FAC, subject to the approval of the FERC

and the Kentucky Commission. Operating expenses and the changes therein for 2010, 2009 and 2008 follow:

The $38 million increase from 2009 to 2010 and $18 million decrease from 2008 to 2009 were primarily due to:

The $4 million decrease from 2009 to 2010 and $61 million decrease from 2008 to 2009 were primarily due to:

The $81 million decrease from 2009 to 2010 and $104 million decrease from 2008 to 2009 were primarily due to:

The $23 million increase from 2009 to 2010 was primarily due to $8 million of increased other operation expenses and $15 million of increased maintenance expenses. The $30 million increase from 2008 to 2009 was primarily due to $28 million of increased other operation expenses and $2 million of increased maintenance expenses.

The $8 million increase from 2009 to 2010 and $28 million increase from 2008 to 2009 were primarily due to:

The $15 million increase from 2009 to 2010 and $2 million increase from 2008 to 2009 were primarily due to:

The $1 million increase from 2009 to 2010 and $55 million increase from 2008 to 2009 were primarily due to:

The $2 million increase from 2009 to 2010 and $14 million decrease from 2008 to 2009 were primarily due to:

(a): Bond interest expense increased in 2010 compared to 2009 due to the issuance of first mortgage bonds in November 2010. Bond interest expense decreased in 2009 compared to 2008 due to the repurchase of bonds in 2008. See Note 11 to our 2010 Annual Financial Statements for further information.
(b): See Notes 3 and 5 to our 2010 Annual Financial Statements for further information regarding interest rate swaps.
(c): Interest expense to affiliated companies decreased in 2010 compared to 2009 primarily due to notes payable to Fidelia Corporation being paid in full in November 2010 as a result of the PPL acquisition. Interest expense to affiliated companies decreased in 2009 compared to 2008 as a result of lower interest rates on intercompany short-term borrowings ($6 million), which was partially offset by increased interest expense as a result of additional debt issued during 2008 ($4 million).

Other income (expense)—net decreased $6 million in 2010 and 2009 primarily due to decreased gains on the sale of our property.

See Note 10 to our 2010 Annual Financial Statements for a reconciliation of differences between the U.S. federal income tax expense at statutory rates and our income tax expense.

A condensed table of cash flows for the following periods in 2010, 2009 and 2008 is presented below. The Predecessor period, January 1, 2010 through October 31, 2010, and the Successor period, November 1, 2010 through December 31, 2010, were aggregated without further adjustment for purposes of comparison with the same periods in 2009 and 2008.

Net cash provided by operating activities decreased by 41%, or $128 million, in 2010 compared with 2009, primarily as a result of changes in working capital, refunds of prior year GSC over-collections, higher interest payments due to an accelerated settlement with the previous owner and higher income tax payments due to higher taxable income. These decreases in cash flow were partially offset by increased earnings and lower storm expenses.

Net cash provided by operating activities increased by 57%, or $112 million, in 2009 compared with 2008, primarily as a result of increased GSC recoveries and favorable changes in working capital. These increases in cash flow were partially offset by lower earnings excluding derivative gains and losses, higher storm expenses and increased pension funding.

We expect to achieve relatively stable cash flows from operations during the next three years although future cash flows may be significantly impacted by changes in economic conditions or new environmental and tax regulations.

The primary use of cash in investing activities is capital expenditures. See "Forecasted Uses of Cash" for details regarding projected capital expenditures for the years 2011 through 2013.

Net cash used in investing activities decreased by 3%, or $6 million, in 2010 compared with 2009, primarily as a result of additional proceeds received of $45 million on the sale of assets and an increase of $2 million in restricted cash collections. These increases in cash flow were partially offset by $34 million in higher capital expenditures and a decrease of $7 million in cash received on the settlement of derivatives.

Net cash used in investing activities decreased by 24%, or $56 million, in 2009 compared with 2008, primarily as a result of a decrease of $57 million in capital expenditures and an increase of

$15 million in cash received on the settlement of derivatives, partially offset by $16 million less in proceeds received on the sale of assets.

Net cash used in financing activities was $14 million in 2010 compared with $132 million in 2009. The change from 2009 to 2010 is a result of new long-term debt issued in excess of retirements, lower dividend payments and less short-term debt repayment.

Net cash used in financing activities was $132 million in 2009 compared with cash provided by financing activities totaling $35 million in 2008. The lower level of cash provided by financing in 2009 was the result of higher dividends and the repayment of short-term debt partially offset by fewer retirements and repurchases of long-term debt.

In the two months of 2010 following the acquisition, cash provided by financing activities of the Successor primarily consisted of the issuance of first mortgage bonds totaling $531 million after discounts, the issuance of intercompany notes totaling $485 million to a PPL subsidiary to repay debt due to an E.ON affiliate upon the closing of the sale and a $163 million drawing under a revolving line of credit. These amounts were offset by the repayment of $485 million to an E.ON affiliate upon the closing of the sale, the repayment of $485 million to a PPL affiliate upon the issuance of the first mortgage bonds, the repayment of $130 million of short-term borrowings due to an affiliated company and the payment of $10 million of debt issuance costs.

In 2010, cash used in financing activities by the Predecessor primarily consisted of the payment of $55 million of dividends to our Parent and decreases in short-term borrowings due to an affiliated company totaling $28 million.

In 2009, cash used in financing activities primarily consisted of the payment of dividends to our Parent totaling $80 million and the repayment of $52 million of short-term borrowings due to an affiliated company.

In 2008, cash provided by financing activities primarily consisted of an increase in short-term borrowings due to an affiliated company of $144 million, the issuance of $95 million of pollution control revenue bonds, the issuance of $75 million of intercompany notes to an E.ON affiliate and the receipt of capital contributions from our Parent totaling $20 million, partially offset by the repurchase of $259 million of pollution control revenue bonds and the payment of $40 million in dividends to our Parent.

As of December 31, 2009, we had a working capital deficiency of $150 million, primarily due to notes payable to affiliated companies totaling $170 million and $120 million of tax-exempt bonds which allow the investors to put the bonds back to us causing them to be classified as "Current portion of long-term debt." As of December 31, 2010, we no longer had a working capital deficiency because the majority of the notes payable to affiliated companies were paid off in conjunction with the PPL acquisition, the $120 million of tax-exempt bonds were no longer classified as "Other current liabilities" by the Successor because we have the intent and ability to utilize our $400 million credit facility that expires in December 2014 to fund any mandatory purchases, and the $163 million in repurchased pollution control bonds that were previously reported on a net basis by the Predecessor are now reported on a gross basis as available for sale debt securities by the Successor. See Notes 11, 18 and 19 to our 2010 Annual Financial Statements for further information.

Auctions for auction rate securities issued by us continued to fail throughout 2010. We held $163 million of our own securities at December 31, 2010 and December 31, 2009, that at one time were auction rate securities. These pollution control bonds were remarketed in January 2011 and currently bear interest at a fixed rate of 1.90% for an intermediate term. See Notes 11, 18 and 19 to our 2010 Annual Financial Statements for further discussion.

We expect to continue to have adequate sources of cash available in the near term, including access to external financing, financing from affiliates and/or infusions of capital from our Parent. Regulatory approvals are required for us to incur additional debt. The FERC authorizes the issuance of short-term debt while the Kentucky Commission authorizes the issuance of long-term debt. In November 2009, we received a two-year authorization from the FERC to borrow up to $400 million in short-term funds. Short-term funds are made available via our participation in an intercompany money pool agreement wherein our Parent and/or KU make funds available to us at market-based rates (based on highly rated commercial paper issues) up to $400 million. We also maintain a $400 million Revolving Credit Agreement discussed below. We currently believe this authorization and these facilities, together with our credit facilities discussed below, provide the necessary flexibility to address any liquidity needs.

Three Months Ended March 31, 2011,
Compared to Three Months Ended March 31, 2010

As a result of the November 1, 2010 acquisition of our Parent by PPL, our results for the three months ended March 31, 2011 are on a different basis of accounting than our results for the three months ended March 31, 2010. When discussing our results of operations for 2011, compared with 2010, material differences resulting from the different bases of accounting will be isolated for purposes of comparability. See "—Predecessor and Successor Financial Presentation" above for further information.

The results for interim periods can be disproportionately influenced by various factors and developments and by seasonal variations, and as such, the results of operations for interim periods do not necessarily indicate results or trends for the year or for future operating results. Due to weather, revenue and earnings are generally highest during the first and third quarters and lowest in the second quarter.

The following table summarizes the significant components of net income for the three months ended March 31, 2011 and 2010, and the changes therein:

		Successor			Predecessor

		Three Months Ended March 31, 2011			Three Months Ended March 31, 2010			Increase (Decrease)
Total operating revenues		$	398		$	366		$	32
Total operating expenses			325			302			23

	Operating income		73			64			9
Interest expense			11			4			7
Interest expense to affiliated companies			—			7			(7	)
Other income (expense)—net			(1	)		(2	)		1

Income from continuing operations, before income taxes			61			51			10
Income tax expense			22			18			4

Net income		$	39		$	33		$	6

The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, Margin. In calculating this measure, utility revenues and expenses associated with approved cost recovery tracking mechanisms are offset. These mechanisms allow for timely recovery of certain expenses, returns on capital investments associated with environmental regulations and performance incentives. As a result, this measure represents the net revenues from our operations. This performance measure is used, in conjunction with other information, internally by senior management and the Board of Directors to manage our operations. We believe that Margin provides another criterion to make investment decisions.

Margin is not intended to replace Operating income, which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to present the results of their operations.

The following table reconciles Operating income to Margin as defined by the Company.

		Successor		Predecessor

		Three Months Ended March 31, 2011		Three Months Ended March 31, 2010
Revenue adjustments(a)
	Commodity swaps marked-to-market(b)	$	—	$	(1	)

Total revenue adjustments		$	—	$	(1	)

Expense adjustments(a)
	ECR mechanism(c)	$	1	$	4
	DSM mechanism(c)		2		4
	GSC mechanism(c)		1		1
	Consumables(d)		6		5
	Transmission(d)		1		1
	Fuel operating and maintenance expenses(e)		—		(2	)

Total expense adjustments		$	11	$	13

The $24 million increase in electric revenues for the three months ended March 31, 2011, compared with the three months ended March 31, 2010, was primarily due to:

(a): The increase in revenues due to the base rate price variance during the three months ended March 31, 2011, compared with the three months ended March 31, 2010, resulted from higher base rates effective August 1, 2010. See Note 3 to our First Quarter Financial Statements for further discussion of the rate cases.
(b): Demand revenue increased during the three months ended March 31, 2011, compared with the three months ended March 31, 2010, as a result of higher demand rates effective August 1, 2010. See Note 3 to our First Quarter Financial Statements for further discussion of the rate cases.
(c): Third-party sales volumes increased as a result of increased generation resulting from improved performance of coal fired generating units and the addition of TC2, a new jointly owned generating facility.
(d): Retail sales volumes decreased during the three months ended March 31, 2011, compared with the three months ended March 31, 2010, primarily as a result of reduced consumption by residential and commercial customers due to milder 2011 winter.

The $8 million increase in natural gas revenues for the three months ended March 31, 2011, compared with the three months ended March 31, 2010, was primarily due to:

(a): Revenues associated with the GSC rate mechanism were included as an offset to Natural gas supply expenses on the Condensed Statement of Income for the three months ended March 31, 2010, and were included in Operating revenues on the Condensed Statement of Income for the three months ended March 31, 2011.
(b): The increase in revenues due to the base rate price variance during the three months ended March 31, 2011, compared with the three months ended March 31, 2010, resulted from higher base rates effective August 1, 2010. See Note 3 to our First Quarter Financial Statements for further discussion of the rate case.
(c): GSC revenues decreased primarily due to lower gas market prices.
(d): Retail sales volumes decreased during the three months ended March 31, 2011, compared with the three months ended March 31, 2010, primarily as a result of reduced consumption due to a decline in total heating degree days. The decrease in revenues due to volume was partially offset by increased WNA revenues resulting from lower natural gas volumes.

The changes in operating expenses for the three months ended March 31, 2011, compared with the three months ended March 31, 2010, are as follows:

The $8 million increase for the three months ended March 31, 2011, compared with the three months ended March 31, 2010, was primarily due to:

The $7 million increase for the three months ended March 31, 2011, compared with the three months ended March 31, 2010, was primarily due to:

See Note 7 to our First Quarter Financial Statements for a reconciliation of differences between the U.S. federal income tax expense at statutory rates and our income tax expense.

We project 2011 earnings to be on par with 2010 as increases associated with the 2010 Kentucky rate cases and lower financing costs due to the issuance in late 2010 of first mortgage bonds which we used to refund higher-cost debt are offset by a decrease in other income due to the recognition of a

regulatory asset associated with the interest rate swaps, as well as higher depreciation. Depreciation is expected to increase due to commencing dispatch of Trimble County Unit 2, or TC2, in January 2011 to serve customer demands. See "Risk Factors" and "A Warning about Forward-Looking Statements" for a discussion of the factors that may impact the 2011 outlook.

We expect to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, our credit facilities and/or infusion of capital from our Parent.

Our cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to, the following:

See "Risk Factors" for further discussion of risks and uncertainties affecting our cash flows.

The $26 million increase in our cash and cash equivalents position was primarily the net result of the following:

On November 1, 2010, we entered into a $400 million unsecured Revolving Credit Agreement with a group of banks. Under this new credit facility, which expires on December 31, 2014, we have the ability to make cash borrowings and to request the lenders to issue letters of credit. Borrowings will generally bear interest at LIBOR-based rates plus a spread, depending upon our senior unsecured long-term debt rating. The new credit facility contains financial covenants requiring our debt to total capitalization to not exceed 70% and other customary covenants. As of March 31, 2011, our debt to total capitalization was 39% as calculated pursuant to the credit agreement. Under certain conditions, we may request that the facility's capacity be increased by up to $100 million. This new credit facility replaced three bilateral credit facilities totaling $125 million that were terminated November 1, 2010. As of March 31, 2011, there were no borrowings outstanding under the new credit facility. We will utilize unused credit facility and money pool balances to fund working capital needs as they arise. See Notes 11, 18 and 19 to our 2010 Annual Financial Statements for further information regarding the

Company's remarketed bonds. See Note 12 to our 2010 Annual Financial Statements and Note 8 to our First Quarter Financial Statements for further information regarding our credit facilities.

Our Parent may make capital contributions to us, which can be used for general business purposes.

We currently do not plan to issue any new long-term debt in 2011 other than the Exchange Bonds. However, we remarketed $163 million of pollution control bonds in January 2011 and expect to remarket an additional $25 million of pollution control bonds in the second half of 2011. See Note 19 to our 2010 Annual Financial Statements for further information.

A downgrade in our credit ratings could impact our ability to access capital and increase the cost of credit facilities and any new debt. Our credit ratings reflect the views of three national rating agencies. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. In March 2011, one national rating agency revised downward our long-term bond ratings and our short-term ratings by one notch, and left the ratings on credit watch with negative implications as a result of PPL's proposed acquisition of the Central Networks business in the United Kingdom. In April 2011, the same agency removed the negative credit watch for all ratings and upgraded by one notch our short-term ratings.

In October 2010, one national rating agency revised downward the short-term credit rating of our pollution control bonds and our issuer rating as a result of the then pending acquisition by PPL. Another raised the long-term rating of our pollution control bonds as a result of the addition of the first mortgage bonds as collateral, while a third national rating agency provided an initial rating of our pollution control bonds and first mortgage bonds. See Note 11 to our 2010 Annual Financial Statements for a discussion of downgrade actions in 2009 and 2008 related to the pollution control bonds caused by a change in the rating of the entity insuring those bonds.

We have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and interest rate instruments, which contain provisions requiring us to post additional collateral, or permit the counterparty to terminate the contract if our credit rating were to fall below investment grade. See Note 5 to our 2010 Annual Financial Statements and Note 4 to our First Quarter Financial Statements for a discussion of Credit Risk Related Contingent Features, including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2010 and March 31, 2011, respectively. At March 31, 2011, if our credit ratings had been below investment grade, we would have been required to prepay or post an additional $62 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate contracts.

In addition to expenditures required for normal operating activities, such as fuel for electric generation, power purchased, payroll and taxes; we currently expect to incur future cash outflows for capital expenditures, various contractual obligations and the payment of dividends.

Our construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric needs of our service area and to comply with environmental regulations. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. We plan to fund capital expenditures through operating cash flows, the credit facility and, if needed, the issuance of long-term debt. We expect our capital expenditures for the three year period ending December 31, 2013 to total approximately $1,561 million, consisting primarily of the following:


Construction of environmental controls and capacity replacement	$	743
Construction of distribution and metering assets		383
Construction of generation assets		164
Construction of coal combustion residual storage structures		91
Redevelopment of Ohio Falls hydroelectric facility		65
Information technology projects		41
Construction of transmission assets		43
Other projects		27
Recoverable environmental assets		4

	$	1,561

Our capital program will focus primarily on compliance with existing or anticipated EPA environmental regulations, aging infrastructure and the need for increased storage capacity for coal combustion by-product materials over the next several years. This program may also be affected in varying degrees by factors such as electric energy demand load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, changes in commodity prices and labor rates and other regulatory requirements. In particular, climate change initiatives, whether via legislative, regulatory or market channels, could restrict or disadvantage power generation from higher-carbon sources. Therefore, we have included estimates regarding significant additional capital expenditures related to pending environmental regulations and legislation. These estimates are subject to final regulations and least cost analysis based on engineering studies. To the extent financial markets see climate change as a potential risk, we may face reduced access to or increased costs in capital markets. Our capital expenditures associated with such actions are preliminarily estimated to be in the $2.0 to $2.5 billion range over the next ten years, although final costs may substantially vary.

See the contractual obligations table below, Note 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements for further information concerning commitments.

The following is provided to summarize contractual cash obligations for periods after December 31, 2010. We anticipate cash from operations and external financing will be sufficient to fund future obligations. See the Statements of Capitalization in our 2010 Annual Financial Statements.

	Payments Due by Period

	2011		2012		2013		2014		2015		Thereafter		Total
Short-term debt(a)	$	175	$	—	$	—	$	—	$	—	$	—	$	175
Long-term debt(b)		—		—		—		—		250		859		1,109
Interest on long-term debt(c)		32		33		36		39		43		826		1,009
Operating leases(d)		5		4		3		3		2		1		18
Unconditional power purchase obligations(e)		20		22		22		23		22		258		367
Coal and natural gas purchase obligations(f)		334		109		112		98		100		36		789
Pension benefit plan obligation(g)		28		33		30		6		1		3		101
Postretirement benefit plan obligations(h)		7		7		7		7		7		35		70
Construction obligations(i)		118		6		4		—		—		—		128
Other obligations(j)		1		1		—		—		—		—		2

	$	720	$	215	$	214	$	176	$	425	$	2,018	$	3,768

This table does not reflect contingent obligations. See Note 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements for further information on contingent obligations.

(a): Represents borrowings of $12 million of debt due to affiliates and debt due to external parties of $163 million within one year.
(b): Reflects principal maturities only based on legal maturity dates and includes the current portion of long-term debt.
(c): Assumes interest payments through maturity. The payments herein are subject to change as payments for debt that is or becomes variable-rate debt have been estimated.
(d): Represents future operating lease payments.
(e): Represents future minimum payments under Ohio Valley Electric Corporation, or OVEC, power purchase agreements through March 13, 2026.
(f): Represents contracts to purchase coal, natural gas and natural gas transportation.
(g): Represents projected cash flows for funding the pension benefit plans as calculated by the actuary. For pension funding information see Note 9 to our 2010 Annual Financial Statements and Note 6 to our First Quarter Financial Statements.
(h): Represents projected cash flows for the postretirement benefit plan as calculated by the actuary. For postretirement funding information, see Note 9 to our 2010 Annual Financial Statements and Note 6 to our First Quarter Financial Statements.
(i): Represents construction commitments, including commitments for the Ohio Falls refurbishment and the Trimble landfill construction including associated material transport systems for coal combustion residuals.
(j): Represents other contractual obligations including the Southwest Power Pool, Inc., or SPP, and the Tennessee Valley Authority, or TVA, coordination agreements.

See "—Application of Critical Accounting Policies and Estimates" for discussion regarding discretionary contributions to the pension and postretirement benefit plans in 2011.

Future dividends may be declared at the discretion of our Board of Directors, payable to our sole shareholder, our Parent. As discussed in Note 12 to our 2010 Annual Financial Statements, our dividend payments may be effectively limited under a covenant in our $400 million revolving line of credit facility. This covenant restricts our debt to total capital ratio to not be more than 70%. This limitation did not restrict our ability to pay dividends at December 31, 2010 or at March 31, 2011. We are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act. We believe, however, that this statutory restriction, as applied to our circumstances, would not be construed or applied by the FERC to prohibit the payment from retained earnings of dividends that are not excessive and are for lawful and legitimate business purposes. See Note 15 to our 2010 Annual Financial Statements and Note 10 to our First Quarter Financial Statements.

In January 2011, we successfully remarketed $163 million of our repurchased pollution control bonds, which were classified as "Available for sale debt securities" on the Balance Sheets at December 31, 2010. We used the proceeds from the remarketed bonds to repay the balance of our credit facility. We will continue to evaluate purchasing, redeeming or remarketing outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.

See Notes 11, 18 and 19 to our 2010 Annual Financial Statements for further information regarding the Company's remarketed bonds. See Note 12 to our 2010 Annual Financial Statements for discussion regarding our credit facilities.

We have very limited off-balance sheet activity. See Note 13 to our 2010 Annual Financial Statements for further discussion.

We are exposed to market risk from equity instruments, interest rate instruments and commodity instruments, as discussed below. However, regulatory cost recovery mechanisms significantly mitigate those risks.

Commodity Price Risk. Our rates are set by regulatory commissions and our fuel costs are recoverable from customers. As a result, we are subject to fuel commodity price risk for only a small portion of on-going business operations. We conduct energy trading and risk management activities to maximize the value of our physical assets at times when the assets are not required to serve our customers, and we manage energy commodity risk using derivative instruments, including swaps and forward contracts. The following chart sets forth the net fair value of our commodity derivative

contracts for the twelve months ended December 31, 2010. See Note 5 to our 2010 Annual Financial Statements, for further information.

The following chart sets forth the changes in the net fair value of our commodity derivative contracts for the three months ended March 31, 2011 and 2010. See Note 4 to our First Quarter Financial Statements for further information.

Interest Rate Risk. We have issued debt to finance our operations, which exposes us to interest rate risk. Our policies allow for the interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate swaps. Pursuant to our company policy, use of these financial instruments is intended to mitigate risk, earnings and cash flow volatility and is not speculative in nature. Our annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant at March 31, 2011 or at December 31, 2010. See Note 5 to our 2010 Annual Financial Statements and Note 4 to our First Quarter Financial Statements for further information.

Securities Price Risk. We have securities price risk through our participation in defined benefit pension and postretirement benefit plans. Declines in the market price of debt and equity securities could impact contribution requirements. See "—Application of Critical Accounting Policies and Estimates—Defined Benefits," Note 9 to our 2010 Annual Financial Statements and Note 6 to our First Quarter Financial Statements for a discussion of the assumptions and sensitivities regarding our defined benefit pension and postretirement benefit plans assumptions.

We are exposed to potential losses as a result of nonperformance by wholesale counterparties of their contractual obligations. We maintain credit policies and procedures to limit counterparty credit risk that include evaluating credit ratings and financial information as well as requiring collateral if the credit exposure exceeds certain thresholds. See Note 5 to our 2010 Annual Financial Statements and Note 4 to our First Quarter Financial Statements for information regarding credit risk and our risk management activities.

We are exposed to potential losses as a result of nonpayment by customers. We maintain an allowance for doubtful accounts composed of accounts aged more than four months. Accounts are written off as management determines them uncollectible. See "—Application of Critical Accounting Policies and Estimates," Note 1 to our 2010 Annual Financial Statements and Note 2 to our First Quarter Financial Statements for further discussion.

Certain of our derivative instruments contain provisions that require us to provide immediate and on-going collateralization on derivative instruments in net liability positions based upon our credit ratings from each of the major credit rating agencies. See Note 5 to our 2010 Annual Financial Statements and Note 4 to our First Quarter Financial Statements for information regarding exposure and the risk management activities.

We and our affiliates engage in related party transactions. See Notes 12 and 15 to our 2010 Annual Financial Statements and Note 10 to our First Quarter Financial Statements for further information.

We are not aware of any material ownership interest or operating responsibility by our executive officers in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with us.

We, along with KU, have been constructing a new 760-Mw capacity base-load, coal-fired unit, TC2, which is jointly owned by us (14.25%) and KU (60.75%), together with the Illinois Municipal Electric Agency and the Indiana Municipal Power Agency (combined 25%). With limited exceptions we took care, custody and control of TC2 on January 22, 2011, and have dispatched the unit to meet customer demand since that date. We and the contractor agreed to a further amendment of the construction agreement whereby the contractor will complete certain actions relating to identifying and completing any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages. See Note 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements for further information.

We continuously re-examine development projects based on market conditions and other factors to determine whether to proceed, to cancel or to expand the projects.

Our financial statements are prepared in compliance with GAAP. The application of these principles necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but also on the results reported through the application of accounting measures used in

preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Our senior management has reviewed the significant and critical accounting policies with the relevant governing bodies of the Company and our Parent, as applicable.

An accounting policy is deemed to be critical if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time the estimate is made, if different estimates reasonably could have been used or if changes in the estimate that are reasonably possible could materially impact the financial statements. Management believes the following critical accounting policies reflect the significant estimates and assumptions used in the preparation of the Financial Statements.

We are a cost-based rate-regulated utility. As a result, our financial statements reflect the effects of regulatory actions. Regulatory assets are recognized for the effect of transactions or events where future recovery is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise be charged to expense. Likewise, regulatory liabilities are recognized for obligations expected to be returned through future regulated customer rates. The effect of such transactions or events would otherwise be reflected as income. In certain cases, regulatory liabilities are recorded based on the understanding with the regulator that current rates are being set to recover costs that are expected to be incurred in the future. The regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC and the Kentucky Commission. See Note 3 to our 2010 Annual Financial Statements and Note 3 to our First Quarter Financial Statements for additional detail regarding regulatory assets and liabilities.

Our employees benefit from both funded and unfunded retirement benefit plans. See Note 1 to our 2010 Annual Financial Statements and Note 1 to our First Quarter Financial Statements for information about policy changes between the Predecessor and Successor and the accounting for defined benefits including our method of amortizing gains and losses. We make various assumptions in arriving at pension and other postretirement benefit costs and obligations. The major assumptions include:

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under the defined benefit pension plans. The return on investments within the plans was approximately 12% for the year ended December 31, 2010. Our benefit plan assets and obligations are re-measured annually using a December 31 measurement date. Due to the PPL acquisition, the benefit plan assets and obligations were also re-measured at October 31, 2010. Our 2010 pension and postretirement benefit cost was approximately $6 million less than 2009. We anticipate our 2011 pension cost will be approximately $4 million less than the 2010 expense. The amount of future funding will depend upon the actual return on plan assets, the discount rate and other factors, but we fund our pension obligations in a manner consistent with the Pension Protection Act of 2006. We made discretionary contributions to our pension plan of $20 million and $8 million in 2010 and 2009, respectively. In January 2011, we contributed $64 million to our pension plans. See Note 19 to our 2010 Annual Financial Statements for further information.

See Note 9 to our 2010 Annual Financial Statements for further information on defined benefits including sensitivity analysis expressing potential changes in expected returns that would result from hypothetical changes to assumptions and estimates, expected rate of return assumptions and health care trends.

We perform a quarterly review to determine if an impairment analysis is required for long-lived assets that are subject to depreciation or amortization. This review identifies changes in circumstances indicating that a long-lived asset's carrying value may not be recoverable. An impairment analysis will be performed if warranted based on the review. For these long-lived assets, such events or changes in circumstances which may indicate an impairment analysis is required include:

For a long-lived asset, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying value to its estimated fair value. Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. We did not recognize an impairment of any long-lived asset in 2010.

Effective with PPL's acquisition of our Parent on November 1, 2010, we recorded $389 million of goodwill. At December 31, 2010, our goodwill remained unchanged. GAAP requires goodwill to be tested for impairment on an annual basis or more frequently if events or circumstances indicate that

assets may be impaired. We perform our annual goodwill impairment test in the fourth quarter. See Note 7 to our 2010 Annual Financial Statements for further discussion.

Goodwill is tested for impairment using a two-step approach. In step 1, we identify a potential impairment by comparing the estimated fair value of the Company (the goodwill reporting unit) to its carrying value, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.

The second step requires a calculation of the implied fair value of goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of our assets and liabilities as if we had been acquired in a business combination and our estimated fair value was the price paid. The excess of our estimated fair value over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.

Determining our fair value is judgmental in nature and involves the use of significant estimates and assumptions. These estimates and assumptions can include revenue growth rates and operating margins used to calculate projected future cash flows, risk adjusted discount rates and future economic and market conditions.

We tested goodwill for impairment in the fourth quarter of 2010 and no impairment was recognized. See Note 7 to our 2010 Annual Financial Statements for further discussion.

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." We do not record the accrual of contingencies that might result in gains, unless recovery is assured. We continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events.

The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by our management. We use our internal expertise and outside experts (such as lawyers and engineers), as necessary, to help estimate the probability that a loss has been incurred and the amount or range of the loss.

We have identified certain other events that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur." See Note 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements for disclosure of other potential loss contingencies that have not met the criteria for accrual.

When an estimated loss is accrued, we identify, where applicable, the triggering events for subsequently adjusting the loss accrual. The triggering events generally occur when the contingency has been resolved and the actual loss is incurred, or when the risk of loss has diminished or been

eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:

We review our loss accruals on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties. This review may result in the increase or decrease of the loss accrual.

We are required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statements of Income, for changes in the obligation due to the passage of time. An offsetting regulatory asset is recognized to reverse the depreciation and accretion expense related to the asset retirement obligation, or ARO, such that there is no income statement impact. The regulatory asset is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated.

In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations. Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset. See Note 4 to our 2010 Annual Financial Statements for further information on AROs.

At December 31, 2010, we had AROs totaling $49 million recorded on the Balance Sheets. Of the total amount, $29 million, or 59%, relates to our ash ponds, landfills and natural gas mains. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.

The following chart reflects the sensitivities related to our ARO liabilities for ash ponds, landfills and natural gas mains as of December 31, 2010:

Significant management judgment is required in developing our provision for income taxes primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. We evaluate our tax positions following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Our management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

On a quarterly basis, we reassess our uncertain tax positions by considering information known at the reporting date. Based on management's assessment of new information, we may subsequently recognize a tax benefit for a previously unrecognized tax position, de-recognize a previously recognized tax position or re-measure the benefit of a previously recognized tax position. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact our financial statements in the future.

The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. We classify unrecognized tax benefits as current, to the extent management expects to settle an uncertain tax position, by payment or receipt of cash, within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria we use to account for an uncertain tax position. See Note 10 to our 2010 Annual Financial Statements and Note 7 to our First Quarter Financial Statements for the required disclosures.

At December 31, 2010, our existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million. This change could result from subsequent recognition, de-recognition and/or changes in the measurement of uncertain tax positions. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitations.

On November 1, 2010, PPL completed the acquisition of our Parent. In accordance with accounting guidance on business combinations, the identifiable assets acquired and the liabilities assumed were measured at fair value at the acquisition date. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The excess of the purchase price over the estimated fair value of the identifiable net assets is recorded as goodwill.

The determination and allocation of fair value to the identifiable assets acquired and liabilities assumed was based on various assumptions and valuation methodologies requiring considerable

management judgment, including estimates based on key assumptions of the acquisition and historical and current market data. The most significant variables in these valuations were the discount rates, the number of years on which to base cash flow projections, as well as the assumptions and estimates used to determine cash inflows and outflows. Although the assumptions applied were reasonable based on information available at the date of acquisition, actual results may differ from the forecasted amounts and the difference could be material.

For purposes of measuring the fair value of the majority of property, plant and equipment and regulatory assets acquired and regulatory liabilities assumed, we determined that fair value was equal to net book value at the acquisition date because our operations are conducted in a regulated environment and the regulatory commissions allow for earning a rate of return on the book value of a majority of the regulated asset bases at rates determined to be fair and reasonable. As there is no current prospect for deregulation in our operating area, it is expected that these operations will remain in a regulated environment for the foreseeable future, therefore management has concluded that the use of these assets in the regulatory environment represents their highest and best use and a market participant would measure the fair value of these assets using the regulatory rate of return as the discount rate, thus resulting in fair value equal to book value.

The fair value of intangible assets and liabilities (e.g., contracts that have favorable or unfavorable terms relative to market), including coal contracts and power purchase agreements, as well as emission allowances, have been reflected on the Balance Sheets with offsetting regulatory assets or liabilities. Prior to the acquisition, we recovered the cost of the coal contracts, power purchases and emission allowances and this rate treatment will continue after the acquisition. As a result, management believes the regulatory assets and liabilities created to offset the fair value adjustments meet the recognition criteria established by existing accounting guidance and eliminate any ratemaking impact of the fair value adjustments. Our customer rates will continue to reflect these items (e.g., coal, purchased power, emission allowances) at their original contracted prices.

We also considered whether a separate fair value should be assigned to our rights to operate within its various electric and natural gas distribution service areas but concluded that these rights only provided the opportunity to earn a regulated return and barriers to market entry, which in management's judgment is not considered a separately identifiable intangible asset under applicable accounting guidance; rather, it is considered going-concern value, or goodwill.

See Notes 2 and 7 to our 2010 Annual Financial Statements for further information.

Recent accounting pronouncements affecting us are detailed in Note 1 to our 2010 Annual Financial Statements.

PPL's Audit Committee has approved the audit fees and audit-related services. The audit-related services include services in connection with regulatory filings, reviews of offering documents and registration statements and internal control reviews.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

On February 23, 2011, PPL's audit committee appointed Ernst &Young LLP as the independent accountant for the Company for 2011. As a result, PricewaterhouseCoopers LLP, or PwC, was dismissed as independent accountant for the Company on February 23, 2011 subject to completion of its procedures on our financial statements as of December 31, 2010 and for the period from January 1, 2010 to October 31, 2010 and the period from November 1, 2010 to December 31, 2010. PwC's dismissal was completed on February 25, 2011.

PwC's reports on the financial statements of the Company as of December 31, 2010 and for the period from January 1, 2010 to October 31, 2010, the period from November 1, 2010 to December 31, 2010, and the year ended December 31, 2009 did not contain any adverse opinion or a disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principle. During the period from January 1, 2009 through February 25, 2011, (1) there were no disagreements with PwC on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of PwC, would have caused PwC to make reference thereto in its reports on the financial statements of the Company as of December 31, 2010 and for the period from January 1, 2010 to October 31, 2010, the period from November 1, 2010 to December 31, 2010, and the year ended December 31, 2009, and (2) there have been no "reportable events" as defined in Item 304(a) (1)(v) of Regulation S-K.

We have provided a copy of the above disclosures to PwC and requested PwC to provide us with a letter addressed to the SEC stating whether or not PwC agrees with those disclosures related to PwC. A copy of PwC's letter, dated April 21, 2011, is attached as Exhibit 16(a) to the registration statement of which this prospectus forms a part.

During the period from January 1, 2009 through February 25, 2011, (1) E&Y had not been engaged as the principal accountant to audit the financial statements of the Company or our predecessor or any of our subsidiaries for any period prior to January 1, 2011, and (2) we have not consulted with E&Y regarding (a) the application of accounting principles to any completed or proposed transaction for any periods prior to January 1, 2011, (b) the type of audit opinion that might be rendered on the Company's financial statements, or (c) any other accounting, auditing or financial reporting matter described in Items 304(a)(2)(i) and (ii) of Regulation S-K. In its capacity as independent accountant of PPL, E&Y was consulted by PPL about various accounting and reporting matters of ours that impacted the consolidated PPL financial statements, primarily around the application of the business combination rules set out in generally accepted accounting principles in the U.S.

See "Financial Condition—Risk Management—Market Risk" above, Notes 5, 6 and 9 to our 2010 Annual Financial Statements and Notes 4, 5 and 6 to our First Quarter Financial Statements for further information.

Louisville Gas and Electric Company, incorporated in Kentucky in 1913, is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy and the storage, distribution and sale of natural gas. We provide electric service to approximately 395,000 customers in Louisville and adjacent areas in Kentucky covering approximately 700 square miles in nine counties. Natural gas service is provided to approximately 320,000 customers in our electric service area and eight additional counties in Kentucky. During 2010, approximately 95% of the electricity we generated was produced by our coal-fired electric generating stations, all equipped with systems to reduce SO₂ emissions. The remainder is generated by natural gas and oil fueled CTs and a hydroelectric power plant. Underground natural gas storage fields help the Company provide economical and reliable natural gas service to customers.

Our affiliate, KU, is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy in Kentucky, Virginia and Tennessee. We and KU became indirect wholly owned subsidiaries of PPL on November 1, 2010. Following the acquisition, our business has not changed. We and KU are continuing as subsidiaries of our Parent, which is now an intermediary holding company in the PPL group of companies.

Our historical financial results are presented using "Predecessor" or "Successor" to designate the periods before or after PPL's acquisition of our Parent. Predecessor covers the time period prior to November 1, 2010. Successor covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL accounting policies and the cost basis of certain assets and liabilities were changed as of November 1, 2010, as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor period are not comparable to the Predecessor period.

Despite the separate presentation, the core operations of the Company have not changed. See Note 1 to our 2010 Annual Financial Statements and Note 1 to our First Quarter Financial Statements for the major differences in Predecessor and Successor accounting policies. See Note 2 to our 2010 Annual Financial Statements for information regarding the acquisition and the purchase accounting adjustments.

For the year ended December 31, 2010, 77% of our total operating revenues were derived from electric operations and 23% from natural gas operations. Electric and natural gas operating revenues and the percentages by class of service on a combined basis for this period were as follows:

Electric Operations. The sources of our electric operating revenues and volumes of sales for the following periods in 2010, 2009 and 2008 were as follows:

Our all-time peak electric load was 2,852 Mw, occurring on August 4, 2010, when the temperature reached a high of 102 degrees Fahrenheit in Louisville.

Our retail electric rates contain an FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. The FAC allows us to adjust billed amounts for the difference between the fuel cost component of base rates and the actual fuel cost, including transportation costs. Credits to customers occur if the actual costs are below the embedded cost component. Additional charges to customers occur if the actual costs exceed the embedded cost component. The amount of the regulatory asset or liability is the amount that has been under- or over-recovered due to timing or adjustments to the mechanism.

Kentucky law permits us to recover the costs of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and byproducts from facilities utilized for production of energy from coal, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism. Pursuant to this mechanism, a regulatory asset or liability is established in the amount that has been under- or over-recovered due to timing or adjustments to the mechanism. This mechanism includes construction work in progress and a return on equity, currently set at 10.63%.

We contract with the TVA to act as our transmission reliability coordinator and SPP to function as our independent transmission operator, pursuant to FERC requirements. The TVA and SPP contracts provide service through August 31, 2011 and August 31, 2012, respectively. See Note 3 to our 2010 Annual Financial Statements and Note 3 to our First Quarter Financial Statements for further information.

We and KU jointly dispatch our generation units with the lowest cost generation used to serve our retail native load. When we have excess generation capacity after serving our own retail native load and our generation cost is lower than that of KU, KU purchases electricity from us. When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of our, we purchase electricity from KU. These transactions are recorded as intercompany wholesale sales and purchases and are recorded by each company at a price equal to the seller's fuel cost. Savings realized from purchasing electricity intercompany instead of generating from their own higher costs units or purchasing from the market are shared equally between the two companies. The volume of energy each company has to sell to the other is dependent on its native load needs and its available generation.

We own 5.63% of OVEC's common stock and are contractually entitled to 5.63% of OVEC's output. Based on nameplate generating capacity, this would be approximately 134 Mw. Additional

information regarding this relationship is provided in Notes 1 and 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements.

Gas Operations. The sources of our natural gas operating revenues and the volumes of sales for the following periods in 2010, 2009 and 2008 were as follows:

During 2010, the maximum daily natural gas sendout was approximately 416,000 Mcf, occurring on December 13, 2010, when the average temperature for the day in Louisville was 15 degrees Fahrenheit. Supply on that day consisted of approximately 305,000 Mcf from pipeline deliveries, approximately 111,000 Mcf from on-system gas storage.

Natural gas billings include a WNA mechanism which adjusts the distribution cost component of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of above- or below-normal weather on residential and commercial revenues. In July 2009, the Kentucky Commission approved our request to make the current WNA mechanism permanent.

Five underground natural gas storage fields, with a current working natural gas capacity of approximately 15 million Mcf, help provide economical and reliable natural gas service to ultimate consumers. By using natural gas storage facilities, we avoid the costs typically associated with more expensive pipeline transportation capacity to serve peak winter heating loads. Natural gas is stored in the summer season for withdrawal in the subsequent winter heating season. Without its storage capacity, we would be required to buy additional natural gas and pipeline transportation services during the winter months when customer demand increases and when the prices for natural gas supply and transportation services are typically at their highest. Several suppliers under contracts of varying duration provide competitively priced natural gas. The underground storage facilities, in combination with our purchasing practices, enable us to offer natural gas sales service at competitive rates. At December 31, 2010, we had a 12 million Mcf inventory balance of natural gas stored underground valued at $60 million.

A number of large commercial and industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through our distribution system. These large commercial and industrial customers account for approximately one-fourth of our annual throughput. The estimated maximum deliverability from storage during the early part of the heating season is expected to be in excess of 350,000 Mcf/day. Under mid-winter design conditions, we expect to be able to withdraw about 307,000 Mcf/day from our storage facilities. The deliverability of natural gas from the storage facilities decreases as storage inventory levels are reduced by seasonal withdrawals.

Demand for and market prices for electricity and natural gas are affected by weather. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis, especially

when more severe weather conditions such as heat waves or winter storms make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities we own and the terms of our contracts to purchase or sell electricity and natural gas.

Our power generating system includes coal-fired steam generating stations, with natural gas and oil fueled CTs that supplement the system during peak or emergency periods. As of December 31, 2010, our system capacity was:

Fuel/Plant					Location

Coal (steam)
	Mill Creek	1,472	100.00	1,472	Jefferson County, KY
	Cane Run	563	100.00	563	Jefferson County, KY
	Trimble County(b)	511	75.00	383	Trimble County, KY
	OVEC—Clifty Creek(c)	1,304	5.63	73	Jefferson County, IN
	OVEC—Kyger Creek(c)	1,086	5.63	61	Gallia County, OH

Total steam		4,936		2,552
Natural gas/oil (CTs)
	Trimble County Units 7-10(d)	640	37.00	237	Trimble County, KY
	E.W. Brown Units 6-7(d)	338	38.00	124	Mercer County, KY
	Trimble County Units 5-6(d)	320	29.00	93	Trimble County, KY
	Paddy's Run Unit 13(d)	158	53.00	84	Jefferson County, KY
	E.W. Brown Unit 5	129	53.00	66	Mercer County, KY
	Paddy's Run Units 11-12	35	100.00	35	Jefferson County, KY
	Zorn	14	100.00	14	Jefferson County, KY
	Cane Run	14	100.00	14	Jefferson County, KY

Total CTs		1,648		667
Hydro
	Ohio Falls Hydroelectric Station	52	100.00	52	Jefferson County, KY

Total hydro		52		52

Total system capacity		6,636		3,271

With limited exceptions we took care, custody and control of TC2 on January 22, 2011, and have dispatched the unit to meet customer demand since that date. We and the contractor agreed to a further amendment of the construction agreement whereby the contractor will complete certain actions relating to identifying and completing any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages. Unit 2 is coal-fired and has a capacity of 760 Mw, of which our share is 108 Mw.

At December 31, 2010, our electric transmission system included 45 substations (32 of which are shared with the distribution system) with transformer capacity of approximately 6,760 Megavolt-ampere, or MVA, and approximately 911 miles of lines. The electric distribution system included 95 substations (32 of which are shared with the transmission system) with transformer capacity of approximately 5,224 MVA and approximately 3,920 miles of overhead lines and 2,350 miles of underground conduit.

Our natural gas transmission system includes 380 miles of transmission mains, consisting of 255 miles of natural gas transmission lines, 119 miles of natural gas storage lines and 6 miles of natural gas CT lines. Our natural gas distribution system includes 4,235 miles of distribution mains.

Substantially all of our real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage and distribution of natural gas, subject to certain exclusions and exceptions, is subject to the lien of the Mortgage, as described in "Description of the Bonds—Security; Lien of the Mortgage."

Additional information regarding our property and investments is provided in Notes 1 and 14 to our 2010 Annual Financial Statements.

Our construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric needs of our service area and to comply with environmental regulations. These needs are continually being reassessed, and appropriate revisions are made, when necessary, in construction schedules. At December 31, 2010, we estimated our capital expenditures for the three-year period ending December 31, 2013 to total approximately $1.6 billion.

In addition to the amounts above, evolving environmental regulations will likely increase the level of capital expenditures over the next several years. At May 23, 2011, we estimated our capital expenditures for environmental control facilities to total approximately $36 million in 2011 and approximately $279 million in 2012. See "Business—Environmental Matters." Future capital requirements may be affected in varying degrees by factors such as electric energy demand, load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, changes in commodity prices and labor rates, further changes in environmental regulations and other regulatory requirements. Credit market conditions can affect aspects of the availability, terms or methods in which we fund our capital requirements. We anticipate funding future capital requirements through operating cash flow, debt and/or infusions of capital from our Parent.

For a discussion of liquidity, capital resources and financing activities, see "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Coal-fired generating units provided approximately 95% of our net kilowatt hour generation for 2010. The remaining net generation was provided by natural gas and oil fueled CTs and a hydroelectric power plant. Coal is expected to be the predominant fuel we use in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in

emergencies. The Company has no nuclear generating units and has no plans to build any in the foreseeable future.

Fuel inventory is maintained at levels estimated to be necessary to avoid operational disruptions at the coal-fired generating units. Reliability of coal deliveries can be affected periodically by a number of factors, including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties.

We have entered into coal supply agreements with various suppliers for coal deliveries for 2011 and beyond and normally augment our coal supply agreements with spot market purchases. We have a coal inventory policy that we believe provides adequate protection under most contingencies.

We expect to continue purchasing most of our coal, which has sulfur content in the 2.0% - 3.5% range, from western Kentucky, southern Indiana, southern Illinois, Ohio, Wyoming and West Virginia for the foreseeable future. This supply, in combination with our SO₂ removal systems, is expected to enable us to continue to provide electric service in compliance with existing environmental laws and regulations. Coal is delivered to our generating stations by a mix of transportation modes, including rail and barge.

We purchase natural gas supplies from multiple sources under contracts for varying periods of time, while transportation services are purchased from Texas Gas Transmission LLC and Tennessee Gas Pipeline Company.

We currently transport natural gas on the Texas Gas system under Rate Schedules No-Notice Service, or NNS, Firm Transport, or FT, and Short-Term Firm, or STF. Our total winter season NNS capacity is 184,900 million British thermal units, or MMBtu, per day and our total summer season NNS capacity is 60,000 MMBtu/day. The three separate NNS agreements, which provide for equal amounts of capacity, are subject to termination by us during 2015, 2016 and 2018. Our FT capacity is 10,000 MMBtu/day throughout the year (winter and summer seasons). The FT agreement is subject to termination by us during 2016. Our winter season STF capacity is 100 MMBtu/day and our summer season capacity is 18,000 MMBtu/day. The STF agreement is subject to termination by us during 2013. We also transport on the Tennessee Gas system under Rate Schedule Firm Transport-A, or FT-A. Our FT-A capacity is 51,000 MMBtu/day throughout the year (winter and summer seasons). The FT-A agreement with Tennessee Gas expires during 2012.

We participate in rate and other proceedings affecting the regulated interstate natural gas pipelines that provide us service. Both Texas Gas and Tennessee Gas have active proceedings at the FERC in which we are participating. Although neither pipeline is currently billing charges subject to refund, Tennessee Gas has filed at the FERC for an increase in base rates as well as other charges with an anticipated effective date of June 1, 2011. However, our current negotiated rate in our transportation agreement with Tennessee Gas insulates us from the potential impact of increases in base rates as proposed by Tennessee Gas for the duration of that agreement.

We also have a portfolio of supply arrangements of various terms with a number of suppliers designed to meet our firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. In tandem with pipeline transportation services, these natural gas supplies provide the reliability and flexibility necessary to serve our natural gas customers.

We are subject to the jurisdiction of the Kentucky Commission and the FERC in virtually all matters related to electric and natural gas utility regulation, and as such, our accounting is subject to the regulated operations guidance of the Financial Accounting Standards Board Accounting Standards

Codification, or FASB ASC. Given our position in the marketplace and the status of regulation in Kentucky, there are no plans or intentions to discontinue the application of the regulated operations guidance of the FASB ASC.

Our base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain regulatory adjustments to exclude non-regulated investments and environmental compliance plans recovered separately through the ECR mechanism. Currently, none of the regulatory assets or regulatory liabilities are excluded from the return on capitalization utilized in the calculation of base rates. Therefore, a return is earned on all regulatory assets existing at the time base rates were determined, except where such regulatory assets were offset by associated liabilities and thus have no impact on capitalization.

PPL Acquisition. On April 28, 2010, PPL entered into a purchase and sale agreement with our former ultimate parent, E.ON US Investments Corp., and E.ON A.G., to purchase all of E.ON US Investments Corp.'s limited liability company interests in our Parent. The transaction was subject to customary closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act, receipt of required regulatory approvals (including state regulators in Kentucky and the FERC) and the absence of injunctions or restraints imposed by governmental entities.

Change of control and financing applications were filed on May 28, 2010 with the Kentucky Commission. An application with the FERC was filed on June 28, 2010. During the second quarter of 2010, a number of parties were granted intervenor status in the Kentucky Commission proceedings and data request filings and responses occurred. Early termination of the Hart-Scott-Rodino waiting period was received on August 2, 2010.

In September 2010, the Kentucky Commission approved a settlement agreement among PPL, joint applicants and all of the intervening parties to PPL's joint application to the Kentucky Commission for approval of its acquisition of ownership and control of our Parent, the Company and KU. In the settlement, the parties agreed that we would commit that no base rate increases would take effect before January 1, 2013. Our increase that took effect on August 1, 2010 (as described below) will not be impacted by the settlement. Under the terms of the settlement, we retain the right to seek approval for the deferral of "extraordinary and uncontrollable costs." Interim rate adjustments will continue to be permissible during that period for existing fuel, environmental and DSM recovery mechanisms. The agreement also substitutes an acquisition savings shared deferral mechanism for the requirement that we file a synergies plan with the Kentucky Commission. This mechanism, which will be in place until the earlier of five years or the first day of the year in which a base rate increase becomes effective, permits us to earn up to a 10.75% return on equity. Any earnings above a 10.75% return on equity will be shared with customers on a 50%/50% basis. The Kentucky Commission's order contained a number of other commitments with regards to operations, workforce, community involvement and other matters.

In October 2010, the FERC approved a September 2010 settlement agreement among the Company, KU, other applicants and protesting parties, and such protests have been withdrawn. The settlement agreement includes various conditional commitments, such as a continuation of certain existing undertakings with protesters in prior cases, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that we have agreed to not seek the same transaction-related cost from retail customers and agreements to coordinate with protesters in certain open or on-going matters.

2010 Electric and Gas Rate Cases. In January 2010, we filed an application with the Kentucky Commission requesting an increase in electric base rates of approximately 12%, or $95 million annually, and our natural gas base rates of approximately 8%, or $23 million annually. The requested rate increase was based on an 11.5% return on equity. A number of intervenors, including the office of the

Kentucky Attorney General, certain representatives of industrial and low-income groups and other third parties, entered the rate cases and submitted filings challenging our requested rate increases, in whole or in part. In June 2010, we and all of the intervenors except for the Kentucky Attorney General agreed to stipulations providing for an increase in our electric base rates of $74 million annually and natural gas base rates of $17 million on an annual basis, and filed a request with the Kentucky Commission to approve such settlement. An order in the proceeding was issued in July 2010, approving the provisions in the stipulation, including a return on equity range of 9.75-10.75%. The new rates became effective on August 1, 2010.

Refund of Over-Collected Amounts. On July 15, 2010, our Parent, on behalf of the Company and KU, submitted an informational filing indicating it had inadvertently over-collected certain costs related to the independent transmission organization and reliability coordinator in rates charged pursuant to the Attachment O formula rate included in the companies' open access transmission tariff. Total refunds being issued in connection with the inadvertent recovery are approximately $1 million. No action has been taken by FERC with respect to this informational filing.

PUHCA. The Company, along with our Parent and KU, are subject to extensive regulation by the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties, payments of dividends out of capital and surplus, financial matters and inter-system sales of non-power goods and services. The Company and KU believe that they have adequate authority, including financing authority, under existing FERC orders and regulations to conduct our business and will seek additional authorization when necessary.

Storm Restoration. In January 2009, a significant ice storm passed through our service area causing approximately 205,000 customer outages, followed closely by a severe wind storm in February 2009, causing approximately 37,000 customer outages. We filed an application with the Kentucky Commission in April 2009, requesting approval to establish a regulatory asset and defer for future recovery approximately $45 million in incremental operation and maintenance expenses related to the storm restoration. In September 2009, the Kentucky Commission issued an order allowing the establishment of a regulatory asset of up to $45 million based on our actual costs for storm damages and service restoration due to the January and February 2009 storms. In September 2009, we established a regulatory asset of $44 million for actual costs incurred. We received approval in our 2010 base rate case to recover this asset over a ten year period with recovery beginning August 1, 2010.

In September 2008, high winds from the remnants of Hurricane Ike passed through the service area causing significant outages and system damage. In October 2008, we filed an application with the Kentucky Commission requesting approval to establish a regulatory asset and defer for future recovery approximately $24 million of expenses related to the storm restoration. In December 2008, the Kentucky Commission issued an order allowing us to establish a regulatory asset of up to $24 million based on our actual costs for storm damages and service restoration due to Hurricane Ike. In December 2008, we established a regulatory asset of $24 million for actual costs incurred. We received approval in our 2010 base rate case to recover this asset over a ten year period beginning August 1, 2010.

2008 Electric and Gas Rate Cases. In July 2008, we filed an application with the Kentucky Commission requesting increases in electric and natural gas base rates. In January 2009, the Company, the Kentucky Attorney General, the Kentucky Industrial Utility Consumers, Inc. and all other parties to the rate case filed a settlement agreement with the Kentucky Commission, under which our natural gas base rates increased by $22 million annually and our electric base rates decreased by $13 million annually. An order approving the settlement agreement was received in February 2009. The new rates were implemented effective February 6, 2009.

WNA. Natural gas billings include a WNA mechanism which adjusts the distribution cost component of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of above- or below-normal weather on residential and commercial revenues. In July 2009, the Kentucky Commission approved our request to make the current WNA mechanism permanent.

GSC. Our natural gas rates contain a GSC, whereby increases and decreases in the cost of natural gas supply are reflected in our rates, subject to approval by the Kentucky Commission. The GSC procedure prescribed by an order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of natural gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of natural gas supply cost from prior quarters is to be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.

FAC. Our retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. The FAC allows us to adjust billed amounts for the difference between the fuel cost component of base rates and the actual fuel cost, including transportation costs. Refunds to customers occur if the actual costs are below the embedded cost component. Additional charges to customers occur if the actual costs exceed the embedded cost component. A regulatory asset or liability is established in the amount that has been under- or over-recovered due to timing or adjustments to the mechanism.

ECR. Kentucky law permits us to recover the costs of complying with the Federal Clean Air Act and those federal, state or local environmental requirements that apply to coal combustion wastes and byproducts from facilities utilized for production of energy from coal, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism. Pursuant to this mechanism, a regulatory asset or liability is established in the amount that has been under- or over-recovered due to timing or adjustments to the mechanism. This mechanism includes construction work in progress and a return on equity, currently set at 10.63%.

In May 2011, we filed notice of intent to file an environmental cost recovery application with the Kentucky Commission for certain upcoming environmental expenditures. The capital cost of the new pollution control facilities for which we intend to seek recovery at this time is estimated to be $1.4 billion. Additional operations and maintenance expenses will be incurred for these projects and are costs that we intend to request to recover through the environmental surcharge mechanism in our application.

DSM. Our rates contain a DSM provision which includes a rate mechanism that provides for concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. DSM consists of energy efficiency programs that are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. The provision allows us to recover revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

For a further discussion of current rates and regulatory matters, see Note 3 to our 2010 Annual Financial Statements and Note 3 to our First Quarter Financial Statements.

General. Protection of the environment is a major priority for us, and a significant element of our business activities. Our properties and operations are subject to extensive environmental-related oversight by federal, state and local regulatory agencies, including via air quality, water quality, waste management and similar laws and regulations. Therefore, we must conduct our operations in accordance with numerous permit and other requirements issued under or contained in such laws or regulations.

Climate Change. Growing global, national and local attention to climate change matters has led to the development of various international, federal, regional and state laws and regulations directly or indirectly relating to emissions of GHGs, including carbon dioxide, which is emitted from the combustion of fossil fuels such as coal and natural gas, as occurs at our generating stations. In particular, beginning in January 2011, GHG emissions from stationary sources, including our generating assets, will be subject to regulation by the EPA under the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act through the GHG "tailoring" rule if a major modification is undertaken at such facilities. Other developing laws and regulations include a variety of mechanisms and structures to regulate GHGs, including direct limits or caps, emission allowances or taxes, renewable generation requirements or standards and energy efficiency or conservation measures, and may require investments in transmission, alternative fuel or carbon sequestration or other emission reduction technologies.

While the final terms and impacts of such developments cannot be estimated, we, as a primarily coal-fired utility, could be adversely affected. Among other emissions, GHGs include carbon-dioxide, which is produced via the combustion of fossil fuels such as coal and natural gas. Our generating fleet is approximately 78% coal-fired, 20% oil/natural gas-fired and 2% hydroelectric based on capacity. During 2010, we produced approximately 95% of our electricity from coal, 4% from natural gas combustion and 1% from hydroelectric generation, based on Mw hours. During 2010, our emissions of GHGs were approximately 16.2 million metric tons of carbon-dioxide equivalents from our owned or controlled generation sources. While our generation activities account for the bulk of our GHG emissions, other GHG sources at the Company include operation of motor vehicles and powered equipment, leakage or evaporation associated with natural gas pipelines, refrigerating equipment and similar activities.

Ambient Air Quality. The Clean Air Act requires the EPA to periodically review the available scientific data for six criteria pollutants and establish concentration levels in the ambient air sufficient to protect the public health and welfare with an extra margin for safety. These standards are known as NAAQS. Each state must identify "nonattainment areas" within its boundaries that fail to comply with the NAAQS and develop a state implementation plan, or SIP, to bring such nonattainment areas into compliance. If a state fails to develop an adequate plan, the EPA must develop and implement a plan. As the EPA increases the stringency of the NAAQS through its periodic reviews, the attainment status of various areas may change, thereby triggering additional emission reduction obligations under revised SIPs aimed to achieve attainment.

In 1997, the EPA established new NAAQS for ozone and fine particulates that required additional reductions in SO₂ and NOx emissions from power plants. In 1998, the EPA issued its final "NOx SIP Call" rule requiring reductions in NOx emissions of approximately 85% from 1990 levels in order to mitigate ozone transport from the midwestern U.S. to the northeastern U.S. To implement the new federal requirements, Kentucky amended its SIP in 2002 to require electric generating units to reduce their NOx emissions to 0.15 pounds weight per MMBtu on a company-wide basis. In 2005, the EPA issued the Clean Air Interstate Rule, or CAIR, which required additional SO₂ emission reductions of 70% and NOx emission reductions of 65% from 2003 levels. The CAIR provided for a two-phase cap and trade program, with initial reductions of NOx and SO₂ emissions due by 2009 and 2010,

respectively, and final reductions due by 2015. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAIR.

In July 2008, a federal appeals court issued a ruling finding deficiencies in the CAIR and vacating it. In December 2008, the Court amended its previous order, directing the EPA to promulgate a new regulation, but leaving the CAIR in place in the interim. The remand of the CAIR results in some uncertainty with respect to certain other EPA or state programs and proceedings and our compliance plans relating thereto, due to the interconnection of the CAIR with such associated programs.

In January 2010, the EPA proposed a revised NAAQS for ozone which would increase the stringency of the standard. In addition, the EPA published final revised NAAQS standards for NO₂ and SO₂ in February 2010 and June 2010, respectively, which are more stringent than previous standards. Depending on the level of action determined necessary to bring local nonattainment areas into compliance with the revised NAAQS standards, our power plants are potentially subject to requirements for additional reductions in SO₂ and NOx emissions.

In August 2010, the EPA issued the proposed CATR, which serves to replace the CAIR. The CATR provides for a two-phase SO₂ reduction program with Phase I reductions due by 2012 and Phase II reductions due by 2014. The CATR provides for NOx reductions in 2012, but the EPA advised that it is studying whether additional NOx reductions should be required for 2014. The CATR is more stringent than the CAIR as it accelerates certain compliance dates and provides for only intrastate and limited interstate trading of emission allowances. In addition to its preferred approach, the EPA is seeking comment on an alternative approach which would provide for individual emission limits at each power plant. The EPA has announced that it will propose additional "transport" rules to address compliance with revised NAAQS standards for ozone and particulate matter which will be issued by the EPA in the future.

Hazardous Air Pollutants. As provided in the Clean Air Act, the EPA investigated hazardous air pollutant emissions from electric utilities and submitted a report to Congress identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the EPA issued the Clean Air Mercury Rule, establishing mercury standards for new power plants and requiring all states to issue new SIPs including mercury requirements for existing power plants. The EPA issued a model rule which provides for a two-phase cap and trade program with initial reductions due by 2010 and final reductions due by 2018. The CAMR provided for reductions of 70% from 2003 levels. The EPA closely integrated the CAMR and CAIR programs to ensure that the 2010 mercury reduction targets would be achieved as a "co-benefit" of the controls installed for purposes of compliance with the CAIR. In addition, in 2006, the Metro Louisville Air Pollution Control District adopted rules aimed at regulating additional hazardous air pollutants from sources including power plants.

In February 2008, a federal appellate court issued a decision vacating the CAMR. In March 2011, the EPA released the proposed utility MACT rule to replace the CAMR. The proposed rule would establish standards for hazardous air pollutants emitted by power plants including mercury, other heavy metals, and acid gases. The emissions limitations specified in the proposed rule are stringent, requiring a 91% reduction in the case of mercury emissions. Upon promulgation of a final rule, facilities would have a short three-year period to comply with the new requirements, with the possibility of a one-year extension from the state. The Company will be unable to determine the exact impact on company operations until such time as a final rule is promulgated by the EPA.

Ash Ponds and Coal-Combustion Byproducts. The EPA has undertaken various initiatives in response to the December 2008 impoundment failure at the TVA's Kingston power plant, which resulted in a major release of coal combustion byproducts into the environment. The EPA issued information requests to utilities throughout the country, including us, to obtain information on their ash ponds and other impoundments. In addition, the EPA inspected a large number of impoundments located at power plants to determine their structural integrity. The inspections included several of our

impoundments, which the EPA found to be in satisfactory condition except for certain impoundments at our Mill Creek and Cane Run stations, which were determined to be in fair condition. In June 2010, the EPA published proposed regulations for coal combustion byproducts handled in landfills and ash ponds. The EPA has proposed two alternatives: (1) regulation of coal combustion byproducts in landfills and ash ponds as a hazardous waste; or (2) regulation of coal combustion byproducts as a solid waste with minimum national standards. Under both alternatives, the EPA has proposed safety requirements to address the structural integrity of ash ponds. In addition, the EPA will consider potential refinements of the provisions for beneficial reuse of coal combustion byproducts.

Water Discharges and PCB Regulations. In March 2011, the EPA released a proposed cooling water intake structure rule pursuant to Section 316(b) of the Clean Water Act. The proposed rule would require a case-by-case review to identify appropriate measures to mitigate the impact of cooling water intake structures on aquatic life. Mitigation measures required as a result of the review could range from use of smaller mesh screens on intake structures to more costly measures such as construction of cooling towers. The exact impact of the rule will depend on the provisions contained in the final rule promulgated by the EPA and the subsequent implementation of the rule by the states. The EPA has also announced plans to develop revised effluent limitation guidelines governing discharges from power plants. The EPA has further announced plans to develop revised standards governing the use of PCB in electrical equipment. We are monitoring these ongoing regulatory developments, but will be unable to determine the impact until such time as new rules are finalized.

Impact of Pending and Future Environmental Developments. As a company with significant coal-fired generating assets, we will likely be substantially impacted by pending or future environmental rules or legislation requiring mandatory reductions in GHG emissions or other air emissions, imposing more stringent standards on discharges to waterways, or establishing additional requirements for handling or disposal of coal combustion byproducts. These evolving environmental regulations will likely require an increased level of capital expenditures and increased incremental operating and maintenance costs by us over the next several years. Due to the uncertain nature of the final regulations that will ultimately be adopted by the EPA, including the reduction targets and the deadlines that will be applicable, we cannot finalize estimates of the potential compliance costs, but should the final rules incorporate additional emissions reduction requirements, require more stringent emissions controls, or implement more stringent byproduct storage and disposal practices, such costs will likely be significant. With respect to NAAQS, CATR, utility MACT rule and coal combustion byproducts developments, based upon a preliminary analysis of proposed regulations, we may be required to consider actions such as upgrading existing emissions controls, installing additional emissions controls, upgrading byproduct disposal and storage and possible early replacement of coal-fired units. Our capital expenditures associated with such actions are preliminarily estimated to be in the $2.0 to $2.5 billion range over the next ten years, although final costs may substantially vary. With respect to potential developments in water discharge, including the recently proposed Section 316(b) cooling water intake rule and the expected revisions to the effluent guidelines, revised PCB standards, or GHG initiatives, costs in such areas cannot be estimated due to the preliminary status or uncertain outcome of such developments, but would be in addition to the above amount and could be substantial. Ultimately, the precise impact on our operations of these various environmental developments cannot be determined prior to the finalization of such requirements. Based upon prior regulatory precedent, we believe that many costs of complying with such pending or future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but we can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

Environmental laws and regulations applicable to our business and governing, among other things, air emissions, wastewater discharges, the use, handling and disposal of hazardous substances and

wastes, soil and groundwater contaminants and employee health and safety are discussed in Note 13 to our 2010 Annual Financial Statements and Note 9 to our First Quarter Financial Statements.

In November 2008, the Commonwealth of Kentucky issued an action plan to create efficient, sustainable energy solutions and strategies and move toward state energy independence. The plan outlines the following seven strategies to work toward these goals:

In December 2009, the Governor of Kentucky's Executive Task Force on Biomass and Biofuels issued a final report to establish potential strategic actions to develop biomass and biofuels industries in Kentucky. The plan noted the potential importance of biomass as a renewable energy source available to Kentucky and discussed various goals or mechanisms, such as the use of approximately 25 million tons of biomass for generation fuel annually, allotment of electricity and natural gas taxes and state tax credits to support biomass development.

In January 2010, a state-established Kentucky Climate Action Plan Council commenced formal activities. The council, which includes governmental, industry, consumer and other representatives, seeks to identify possible Kentucky responses to potential climate change and federal legislation, including increasing statewide energy efficiency, energy independence and economic growth. The council has established various technical work groups, including in the areas of energy supply and energy efficiency/conservation, to provide input, data and recommendations.

During sessions of the Kentucky General Assembly, legislators have introduced or are expected to introduce various bills with respect to environmental or utility matters, including potential requirements relating to renewable energy portfolios, energy conservation measures, coal mining or coal byproduct operations and other matters. The most recent legislative session ended without material developments in these areas. Legislative and regulatory actions as a result of future proposals and their impact on us, which may be significant, cannot currently be predicted.

We had 1,022 employees at December 31, 2010, consisting of 1,018 full-time employees and 4 part-time employees. Of the total employees, 686, or 67%, were operating, maintenance and construction employees represented by the International Brotherhood of Electric Workers Local 2100. In November 2008, we and our employees represented by the IBEW Local 2100 entered into a three-year collective bargaining agreement that provides for negotiated increases or changes to wages, benefits or other provisions.

There are currently no other electric utilities operating within our electric service areas. Neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of any legislative or regulatory actions regarding industry restructuring and their impact on us, which may be significant, cannot currently be predicted. See Note 3 to our 2010 Annual Financial Statements for further information.

Alternative energy sources such as electricity, oil, propane and other fuels provide indirect competition for natural gas revenues. Marketers may also compete to sell natural gas to certain large end-users. Approximately 25% of our annual throughput is purchased by large commercial and industrial customers directly from alternate suppliers for delivery through our distribution system. We do not profit from its sale of natural gas as a commodity; therefore, customer natural gas purchases from alternative suppliers do not impact profitability. In addition, some large industrial and commercial customers may be able to physically bypass our facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.

In April 2010, the Kentucky Commission commenced a proceeding to investigate natural gas retail competition programs, their regulatory, financial and operational aspects and potential benefits, if any, of such programs to Kentucky consumers. A number of entities, including the Company, were parties to the proceeding. In December 2010, the Kentucky Commission issued an order in the proceeding declining to endorse natural gas competition at the retail level, noting the existence of a number of transition or oversight costs and an uncertain level of economic benefits in such programs. With respect to existing natural gas transportation programs available to large commercial or industrial users, the order indicates that the Kentucky Commission will review the utilities' current tariff structures, user thresholds and other terms and conditions of such programs, as part of such utilities' next regular natural gas rate cases.

For a discussion of the significant legal proceedings, including, but not limited to, certain rates and regulatory, environmental, climate change, litigation and other matters involving the Company, reference is made to the information in Notes 3 and 13 to our 2010 Annual Financial Statements.

In the normal course of business from time to time, other lawsuits, claims, environmental actions and other governmental proceedings arise against the Company. To the extent that damages are assessed in any of these actions or proceedings, the Company believes that its insurance coverage is adequate. Although we cannot accurately predict the amount of any liability that may ultimately arise with respect to such matters, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on our financial condition or results of operations.

We provide electric delivery service and natural gas distribution service in our various service areas pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by state legislatures, cities or municipalities or other entities.

Set forth below is information regarding our executive officers and members of our board of directors. There are no family relationships among any of the executive officers or directors, nor, except as described under "Executive Compensation—Employment-Related Arrangements" with respect to Messrs. Staffieri and McCall, is there any arrangement or understanding between any executive officer or director and any other person pursuant to which the officer was selected.

There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer or director during the past ten years.

Officers generally serve in the same capacities at our Parent, the Company and KU.

Name		Position

Victor A. Staffieri	56	Chairman, President, Chief Executive Officer and Director
S. Bradford Rives	52	Chief Financial Officer, Principal Accounting Officer and Director
John R. McCall	67	Executive Vice President, General Counsel, Corporate Secretary, Chief Compliance Officer and Director
Chris Hermann	63	Senior Vice President—Energy Delivery and Director
Paul W. Thompson	54	Senior Vice President—Energy Services and Director
Paul A. Farr	43	Director
William H. Spence	54	Director

Victor A. Staffieri has been Chairman, President and Chief Executive Officer of the Company, KU and the Parent since 2001. Before he was elected to his current position, Mr. Staffieri was President and Chief Operating Officer of LG&E Energy Corp. ("LG&E Energy"), the predecessor to the Parent, from February 1999 to April 2001 and President of the Company and KU from June 2000 to April 2001. He served as Chief Financial Officer of LG&E Energy and the Company from May 1997 to February 2000 and Chief Financial Officer of KU from May 1998 to February 1999. He served as President of Distribution Services Division of LG&E Energy from December 1995 to May 1997, President of the Company from January 1994 to December 1995 and Senior Vice President of Public Policy of LG&E Energy and the Company from November 1992 to December 1993 and General Counsel. Mr. Staffieri has been a Director of the Company, KU and the Parent since April 2001. He served as a Director of E.ON UK (previously, Powergen PLC) from April 2001 to January 2004 and of Edison Electric Institute since 2001. He holds a bachelor's degree from Yale University and a juris doctor degree from Fordham University School of Law.

S. Bradford Rives has been Chief Financial Officer of the Company, KU and the Parent since 2003 and serves as the Company's Principal Accounting Officer. Before he was elected to his current position, Mr. Rives was Senior Vice President—Finance and Controller of LG&E Energy, the Company and KU from December 2000 to September 2003. He has been a Director of the Parent since 2003 and the Company and KU since January 2004. Mr. Rives is a certified public accountant and is a member of the Kentucky Society of Certified Public Accountants. He has a bachelor's degree in accounting from the University of Kentucky, and a juris doctor degree from the University of Louisville School of Law. Mr. Rives is a member of the Kentucky and Louisville Bar Associations.

John R. McCall has been Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer of the Company, KU and the Parent since 2006 and Executive Vice President, General Counsel and Corporate Secretary of the Company and the Parent since July 1994 and of KU since May 1998. Mr. McCall has been a Director of the Parent since December 2003 and of

the Company and KU since January 2004. Mr. McCall has a bachelor's degree and a juris doctor degree from Vanderbilt University. He is a member of the American, Kentucky and Louisville Bar Associations. He is a member of the Legal Committee of Edison Electric Institute.

Chris Hermann has been Senior Vice President—Energy Delivery of the Company, KU and the Parent since 2003. Before he was elected to his current position, Mr. Hermann was Senior Vice President—Distribution Operations, of LG&E Energy, the Company and KU from December 2000 to February 2003. Mr. Hermann has been a Director of the Company, KU and the Parent since January 2005. Mr. Hermann serves on the American Gas Association Advisory Board, Safety Task Force Board and Strategic Planning Committee, Southern Gas Association Board. He received a B.S. in mechanical engineering from the University of Louisville.

Paul W. Thompson has been Senior Vice President—Energy Services of the Company, KU and the Parent since 2000. Before he was elected to his current position, Mr. Thompson was Senior Vice President—Energy Services of LG&E Energy from August 1999 to June 2000. He served as Group Vice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999 and as Vice President—Retail Electric Business for the Company from December 1998 to August 1999. Mr. Thompson served as Vice President—Retail Electric Business for the Company from September 1996 to June 1998 and as Vice President, Business Development for LG&E Energy from July 1994 to September 1996. Previously, Mr. Thompson served in several management positions for Koch Industries and Lone Star Technologies. Mr. Thompson has a bachelor's degree in mechanical engineering from the Massachusetts Institute of Technology, and a master's degree in business administration in finance and accounting from the University of Chicago. Mr. Thompson has been a director of the Company, KU and the Parent since January 2005. Mr. Thompson is a member of the American Society of Mechanical Engineers. He is a board member and former Chairman of the Board of the FutureGen Industrial Alliance. He serves on the Boards of Ohio Valley Electric Corp., Electric Energy Inc., and the Center for Applied Energy Research.

Paul A. Farr has been Executive Vice President and Chief Financial Officer of PPL Corporation since April 2007. Prior to assuming his current position in April of 2007, Mr. Farr was named Senior Vice President-Financial in August 2005, Vice President and Controller in August 2004 and served as Controller until January 2006. Prior to serving in his PPL Corporation positions, Mr. Farr served as Senior Vice President of PPL Global, LLC, a subsidiary of PPL Corporation that owns and operates electricity businesses in the United Kingdom, as well as formerly in Latin America, from January 2004, as well as Vice President-International Operations from June 2002 and Vice President since October 2001. Mr. Farr also served for several years as Vice President and Chief Financial Officer of PPL Montana, LLC, and in other management positions at PPL Global. Before joining PPL in 1998, Mr. Farr served as international project finance manager at Illinova Generating Company, as international tax manager for Price Waterhouse LLP and as an international tax senior at Arthur Andersen. Mr. Farr earned a bachelor's degree in accounting from Marquette University and a master's degree in management from Purdue University. He is a certified public accountant and also serves on the boards of the Company, KU, PPL Electric Utilities Corporation and PPL Energy Supply, LLC. Mr. Farr has been a director of the Company since November 2010.

William H. Spence has been Executive Vice President and Chief Operating Officer of PPL Corporation since June 2006, and President of PPL Generation, LLC, a subsidiary of PPL, since June 2008. Prior to joining PPL in June 2006, Mr. Spence had 19 years of service with Pepco Holdings, Inc. and its heritage companies, Delmarva Power and Conectiv. He served as Senior Vice President of Pepco Holdings from August 2002 and as Senior Vice President of Conectiv Holdings since September 2000. He joined Delmarva Power in 1987 in that company's regulated gas business, where he held various management positions before being named Vice President of Trading in 1996. Mr. Spence earned a bachelor's degree in petroleum and natural gas engineering from Penn State University and a master's degree in business administration from Bentley College. He also serves on the boards of the Company, KU, PPL Electric Utilities Corporation and PPL Energy Supply, LLC. Mr. Spence has been a director of the Company since November 2010.

On November 1, 2010, PPL acquired our Parent, and its subsidiaries, including KU and us, from the German company E.ON AG, which we refer to as the acquisition or change in control. In this Compensation Discussion and Analysis and the executive compensation tables and narratives that follow, we discuss 2010 compensation paid to our named executive officers for services provided to our Parent, KU and us. The information we are providing relates to total compensation for our named executive officers for 2010, without any allocation among the companies.

The E.ON AG Board of Management, a committee comprised of E.ON AG senior management, set compensation for our named executive officers for 2010 prior to the acquisition. The E.ON AG Board of Management consulted with Mr. Staffieri, the E.ON AG chairman of the board, chief executive officer and president and the E.ON AG senior vice president of group corporate officer resources in connection with setting executive compensation. Because E.ON AG, our Parent, KU and the Company are not subject to the listing standards of a U.S. national securities exchange, there was no requirement for a compensation committee or other committee of independent board directors to determine compensation for our named executive officers for 2010. When Mr. Staffieri became an executive officer of PPL, which is a listed company, the PPL Compensation, Governance and Nominating Committee, a committee of independent directors as required by the New York Stock Exchange, assumed oversight of his compensation.

In connection with the acquisition, contractual commitments provide for continuation, for 24 months, of specified components of the compensation program in place for our named executive officers, on terms materially no less favorable in the aggregate than the then-current terms. This included each named executive officer's annual base salary, short-term incentive opportunity and cash-based long-term incentive opportunity in addition to specified benefits, including the supplemental executive retirement plan, a non-qualified deferred compensation plan and certain perquisites.

The PPL Compensation, Governance and Nominating Committee, at its October 21, 2010 meeting, ratified or approved the following for Mr. Staffieri:

The Compensation, Governance and Nominating Committee also ratified Mr. Staffieri's amended and restated employment and severance agreement with our Parent and his participation in the LG&E Energy Corp. Supplemental Executive Retirement Plan and the E.ON U.S. LLC Nonqualified Savings Plan. In January 2011, the Compensation, Governance and Nominating Committee approved payment of Mr. Staffieri's 2010 short-term incentive award.

Compensation for the other named executive officers after the change in control was reviewed by the PPL vice president—human resources and services, the PPL chief executive officer and the PPL chief operating officer. The Corporate Leadership Council approved grants of restricted stock units to the other named executive officers for retention purposes and approved payment of their 2010 short-term incentive awards in January 2011.

The named executive officers' compensation for 2010 consisted primarily of base salary, short-term incentive awards, long-term incentive awards and payments relating to the acquisition. The acquisition-related payments included a cash divestiture incentive payment, as well as payments relating to incentive awards that accelerated because the acquisition constituted a change in control. Mr. Staffieri and Mr. McCall had employment agreements pursuant to which they were guaranteed minimum base salaries and target short-term and long-term incentive award opportunities.

Target direct compensation for 2010 included base salary, short-term incentive and long-term incentive awards. Target incentive levels were determined as a percentage of base salary, so that any increase in base salary resulted in an increase in the target short-term and long-term incentive awards.

Table 1 below shows the allocation of each element of total target direct compensation for the named executive officers for 2010.

Table 1
Elements of Target Compensation as a Percentage of Total Target Direct Compensation—2010

In December of each year, E.ON AG's Board of Management reviewed and approved the base salaries for the named executive officers. Due to 2010 budget constraints, base salaries for the named executive officers were frozen until the E.ON AG Board of Management approved an increase of three percent on March 3, 2010, retroactive to January 1, based upon recommendations by Mr. Staffieri. Mr. Staffieri received no increase.

In March 2010, the E.ON AG Board of Management granted short-term incentive awards to the named executive officers under the Powergen Short-Term Incentive Plan. E.ON AG's short-term incentive award program was designed to reward annual performance compared to financial, business and individual goals determined jointly by Mr. Staffieri and the E.ON AG Board of Management. The

short-term incentive award, unlike base salary, was "at risk" because awards were based on achievement of these financial, business and individual goals. Actual payments could range from 0 percent to 200 percent of the target award.

Table 3
2010 Short-Term Incentive Targets as a Percentage of Base Salary by Position—
Effective January 1, 2010

The E.ON AG Board of Management approved the short-term incentive goals and weightings for 2010 as outlined in the table below.

In connection with the acquisition, the PPL vice president—human resources and services and Mr. Staffieri discussed alternatives to the E.ON AG adjusted earnings before interest and taxes, or EBIT, measure. Because E.ON AG would not be in a position to share financial information after the closing of the acquisition and the public release of E.ON AG financial results would not be timely as to the normal PPL incentive award payment practices, the E.ON AG adjusted EBIT measure was replaced with a combined LG&E and KU Energy LLC adjusted EBIT and PPL earnings per share measure. In addition, Messrs. Rives', McCall's and Thompson's awards were modified to add lost-time injury frequency/safety as a goal with a 10 percent weighting, and the weighting assigned to the individual management effectiveness component of their awards was reduced to 40 percent. The short-term incentive goals and weightings after the change in control are outlined below.

Performance could range from 0 percent to 200 percent of target for each goal, but the award formula is additive, meaning that a zero result for one goal would not cause the named executive officer to forfeit the entire award. Payouts for percentile ranks falling between threshold and target and between target and maximum would be interpolated. To earn 100 percent of the total target award, the named executive officers had to attain 100 percent of target on all of the goals.

EBIT and EPS Measures. The 2010 short-term incentive financial measures were (i) combined LG&E and KU Energy LLC adjusted EBIT and PPL earnings per share (EPS) from ongoing operations and (ii) full year LG&E and KU Energy LLC adjusted EBIT. Adjusted EBIT is equal to earnings before interest and taxes as reported in our Parent's financial statements, adjusted for impacts related to the acquisition and was targeted for the full year at $490 million. For the combined adjusted EBIT and PPL EPS goals, the targets were based on the full year adjusted EBIT of $490 million and EPS of $2.87; after determining performance for the full year in relation to the targets, the amounts were then prorated—¹⁰/12 for adjusted EBIT and ²/12 for EPS. No payment would be earned under the financial measures component of the award if PPL EPS were below $2.61 and adjusted EBIT did not exceed $343 million. The maximum payment would be earned for achievement of PPL EPS of $3.10 or more and adjusted EBIT was at least $637 million.

LTIF/Safety Measure. The named executive officers' operational goal was "lost-time injury frequency," or LTIF, based on a target that was established by the E.ON AG Board of Management, taking into consideration prior year results, with the expectation that current year results would be better than the prior year.

The goals, weightings and actual results for the adjusted EBIT, EPS and LTIF/Safety goals were as follows:

Goal			Target	Actual Results

Financial
	Combined LG&E and KU Energy LLC Adjusted EBIT and	16.666	Full year: $490 million (min: $343 million) (max: $637 million)	$551 million (between target and maximum)	23.665
	PPL EPS	3.334	Full year: $2.87 (min: $2.61) (max: $3.10)	$3.13 (above maximum)	6.668
	LG&E and KU Energy LLC Adjusted EBIT	30.00	Full year: $490 million (min: $343 million) (max: $637 million)	$551 million (between target and maximum)	42.60
Lost-Time Injury Frequency/Safety
	Employee Lost-Time Injury Frequency	2.50	£ 1.2	0.38 (above maximum)	5.00
	Contractor Lost-Time Injury Frequency	2.50	£ 1.3	0.95 (above maximum)	5.00
	Safety Systems and Safety Culture Indicator	5.00	Implement program to reinforce safety culture	Satisfied (at target)	5.00
				Total	87.933
Management Effectiveness		40.00	See discussion below

Management Effectiveness Measure. The E.ON AG Board of Management, the E.ON AG chairman of the board, chief executive officer and president and Mr. Staffieri agreed on Mr. Staffieri's individual management effectiveness goals. Each of the other named executive officers agreed on his individual management effectiveness goals with Mr. Staffieri, who then submitted the goals to the E.ON AG Board of Management and the E.ON AG chairman of the board, chief executive officer and president for approval.

Victor A. Staffieri. Mr. Staffieri's individual performance goals for 2010 were as follows:

In determining Mr. Staffieri's performance for the short-term incentive award, the PPL Compensation, Governance and Nominating Committee considered the recommendations of James H. Miller, PPL chief executive officer. In developing his recommendations, Mr. Miller consulted with William H. Spence, PPL chief operating officer, and conducted a performance review at the end of 2010 with assessment input from Mr. Spence and the PPL vice president-human resources and services. The assessment contained two dimensions—an assessment of attainment of overall objectives for the year, as well as an assessment of values, behaviors and key attributes.

In particular, the PPL Compensation, Governance and Nominating Committee considered that, under Mr. Staffieri's leadership:

Mr. Staffieri's performance was rated at 100 percent, resulting in the management effectiveness component of his award to be earned at 40 percent.

When determining achievement of individual objectives for the other named executive officers, Mr. Staffieri, the PPL vice president—human resources and services, Mr. Miller and Mr. Spence assessed each named executive officer's performance based on his individual management effectiveness goals. The assessments were further reviewed by the PPL Corporate Leadership Council. The overall rating also reflected an element of how the named executive officers achieved objectives consistent with company values and behaviors.

S. Bradford Rives. Mr. Rives' individual performance goals for 2010 were as follows:

Mr. Rives' performance was rated at 140 percent, resulting in the management effectiveness component of his award to be earned at 56 percent.

John R. McCall. Mr. McCall's individual performance goals for 2010 were as follows:

Mr. McCall's performance was rated at 140 percent, resulting in the management effectiveness component of his award to be earned at 56 percent.

Chris Hermann. Mr. Hermann's individual performance goals for 2010 were as follows:

The performance assessment of Mr. Hermann took into consideration that he and his team:

Mr. Hermann's performance was rated at 135 percent, resulting in the management effectiveness component of his award to be earned at 54 percent.

Paul W. Thompson. Mr. Thompson's individual performance goals for 2010 were as follows:

Mr. Thompson's performance was rated at 140 percent, resulting in the management effectiveness component of his award to be earned at 56 percent.

The following table shows each goal as a percentage of the total target award earned and the total goal results.

The total goal results were then used to determine short-term incentive payments as follows:

The named executive officers received the following short-term incentive award payments, which are included in the Summary Compensation Table in the column headed "Non-Equity Incentive Plan Compensation."

The E.ON AG Board of Management granted long-term incentive awards payable in cash to each named executive officer in 2010. The long-term incentive awards had two components:

The value of the performance units was dependent upon company performance against a value-added target at the end of the 2010-2012 performance period. Value-added is the amount by which return on capital employed exceeds the target, based on average cost of capital. Payment could range from 0 percent to 150 percent of target. Because of the change in control, vesting of the performance units was accelerated and they were paid out at target.

The value of share performance rights was based on E.ON AG total shareholder return in comparison to the Dow Jones STOXX Utilities Index (Total Return EUR) over the 2010-2013 performance period, which we refer to as the performance factor, and the closing value of E.ON AG stock. Executives would receive payment at the end of the performance period equal to:

# of Share Performance Rights Granted × Performance Factor × Closing Value of E.ON AG Stock

E.ON AG's calculation agent, HSBC Trinkaus, calculated the closing value of E.ON AG stock, which is the average closing price for the 60 trading days preceding the end of the performance period. Values provided by HSBC Trinkaus were in Euros and converted to US currency using the average

exchange rate for the 60 trading days preceding the end of the performance period. Payment of these awards was determined as follows:

If the performance of E.ON AG stock during the performance period was identical to the performance of the Dow Jones STOXX Utilities Index, the performance factor is "1." If E.ON AG's total shareholder return under-performed the Dow Jones STOXX Utilities Index, the target number of share performance rights granted would be decreased by five percent for every one percent of under-performance, with under-performance of 20 percentage points or more resulting in no payment. If E.ON AG's total shareholder return outperformed the Dow Jones STOXX Utilities Index, the target number of share performance rights granted would be increased by one percent for every one percent of outperformance, with a maximum performance factor of 3. The maximum amount payable for this award was three times the initial E.ON AG share price of €27.25, or €81.75, per performance right. The grant date fair value of the share performance rights is included in the Summary Compensation Table in the column headed "Stock Awards" and in the Grants of Plan-Based Awards During 2010 table in the column headed "Grant Date Fair Value of Stock and Option Awards."

The long-term incentive awards granted by the E.ON AG Board of Management to the named executive officers in 2007 for the 2007-2009 performance period vested and were paid in cash in January 2010.

The performance unit awards granted under the LG&E Energy Corp. Long-Term Performance Unit Plan were based on a value-added target. Results were 119 percent of target. The results were approved by the E.ON AG Board of Management at its January 2010 meeting.

The share performance rights granted under the E.ON Share Performance Plan were paid based on a performance factor of 1.11, indicating that E.ON AG's total shareholder return outperformed the Dow Jones STOXX Utilities Index by 11 percentage points, and an average closing value of E.ON AG stock of €81.76, which was converted to $121.02, each as adjusted. E.ON AG effected a 3-for-1 stock split, effective August 1, 2008. While the share performance rights were not adjusted for the split, in determining payment, the average closing value was calculated and then adjusted by HSBC Trinkaus to give effect to the stock split.

The payments in 2010 of these long-term incentive awards are included in Table 11 below.

Accelerated Payment of Outstanding Long-Term Incentive Awards Granted in 2008, 2009 and 2010 upon Change in Control

Outstanding long-term incentive awards granted in 2008, 2009 and 2010 vested and were paid out as a result of the November 1, 2010 change in control.

The LG&E Energy Corp. Long-Term Performance Unit Plan provides for payment of outstanding awards upon a change in control based on the higher of actual performance or target. Payment of these awards was based on actual results for 2008, 2009 and the nine month period ended September 30, 2010 and results at target for 2011 and 2012.

Payments from the E.ON Share Performance Plan were based on E.ON AG total shareholder return for the period ending September 30, 2010 and the average closing value of E.ON AG stock of €22.29, or $29.64, as determined by HSBC Trinkaus, for the 60 trading days preceding November 1, 2010, the effective date of the change in control.

Table 13 below reflects payments made in 2010 as a result of accelerated vesting upon the change in control under the E.ON Share Performance Unit Plan and the LG&E Energy Corp. Long-Term Performance Unit Plan.

In 2008, the E.ON AG Board of Management granted an incentive award opportunity to the named executive officers in connection with the consummation of a change in control of our Parent.

Payment of the award opportunity depended upon objective factors—the price paid for our Parent—and subjective factors—preparation of information, data room and management presentations, support of negotiations and definitive documents, participation in regulatory proceedings and execution of other tasks in support of the change in control. Possible payments ranged from 0 percent to 150 percent of base salary and target short-term incentive for the year in which the change in control occurred. The E.ON AG chairman, chief executive officer and president assessed the named executive officers' performance as a team with respect to this award opportunity and determined that they had earned the maximum payments as listed in the table below.

PPL entered into retention agreements with the named executive officers on December 1, 2010, pursuant to which they were granted restricted stock units payable in PPL common stock. The named executive officers receive cash dividend-equivalents during the period of restriction that are not subject to forfeiture. In his retention agreement, Mr. Staffieri also agreed to modify the perquisites he received pursuant to his employment and severance agreement and gave up an employer-paid country club membership and company-paid use of air transportation for any non-business purpose, as well as, effective January 1, 2011, tax gross-up payments on his perquisites. PPL entered into the retention agreements to encourage the named executive officers to remain employed affiliates of by PPL and to compensate Mr. Staffieri for the loss of these perquisites.

The named executive officers must remain continuously employed by affiliates of PPL through the vesting date, unless the executive's employment is terminated due to death or disability. They must also sign a release of liability agreement to receive payment of their awards. If employment is terminated due to death or disability, payment will be prorated.

The named executive officers received the perquisites and other benefits listed below in 2010. As discussed above, in connection with the change in control, Mr. Staffieri agreed to modify his perquisites.

Our Parent paid a full tax gross-up to executives for additional tax expenses in connection with personal usage of executive auto, any difference between the auto lease allowance and total lease cost that was paid in cash, country/luncheon club membership, tax preparation fees and financial planning services and spousal air travel, and for Mr. Staffieri, life insurance benefits.

The named executive officers participate in the E.ON U.S. LLC Nonqualified Savings Plan and may elect to defer up to 75 percent of their base pay and short-term incentive pay. Our Parent matches executive contributions to the E.ON U.S. LLC Nonqualified Savings Plan equal to 70 percent of the first six percent deferred.

In October 2010, our Parent entered into amended and restated employment and severance agreements with Messrs. Staffieri and McCall that replaced previous agreements, dated February 25, 2000, as amended, with LG&E Energy Corporation and Powergen plc. The agreements provide for changes needed to reflect the change in control, Messrs. Staffieri's and McCall's retention with our Parent and their anticipated roles after the change in control. The agreements have an initial two-year term, with automatic one-year extensions and provide for minimum base salary, target short-term incentive and long-term incentive levels, participation in employee benefit programs, severance and change in control protection, tax gross-ups, perquisites and other benefits substantially similar to those in the previous agreements.

The other named executive officers entered into retention and severance agreements in October 2010 that replaced previous agreements with LG&E Energy Corp. and E.ON AG. Messrs. Rives', Hermann's and Thompson's agreements provide for changes needed to reflect the change in control,

and their retention with our Parent. The new retention and severance agreements have an initial two-year term, with automatic one-year extensions and provide for severance payments, tax gross-ups and benefits upon specified terminations of employment including those in connection with a future change in control, excluding a change in control of PPL, that are substantially similar to those in the previous agreements. The benefits provided under the named executive officers' agreements replaced any other benefits provided by our Parent or any prior employment-related agreement. Additional details on the terms of these employment and severance agreements and the retention and severance agreements are contained in the "Employment-Related Arrangements" section.

Sections 280G and 4999. While the old employment agreements provided for benefits upon termination of employment in connection with a change in control and a gross-up payment, the November 1, 2010 change in control did not qualify as a change in ownership or effective control under Internal Revenue Code Sections 280G and 4999. As discussed above, our Parent entered into agreements with each of the named executive officers that provide benefits to the executives upon specified terminations of employment in connection with any future change in control, excluding a change in control of PPL. The agreements provide for tax protection in the form of a gross-up payment to reimburse the executive for any excise tax under Internal Revenue Code Section 4999, as well as any additional income and employment taxes resulting from such reimbursement. Pursuant to the excise tax provisions, a 20 percent tax is levied on excess parachute payments. Our Parent has determined that it is appropriate to provide protection to the named executives from adverse consequences of the additional tax.

The following table summarizes all compensation for the chief executive officer, chief financial officer, and the next three most highly compensated executives, or "named executive officers," in 2010. During 2010, the named executive officers received compensation for services provided to our Parent, KU and us. In the tables, we include all compensation for services to any of these companies during 2010, without any allocation among the companies. All of the named executive officers also served as our directors and the directors of our Parent and KU during 2010, but received no compensation for board service.

Name and Principal Position (a)

Victor A. Staffieri Chief Executive Officer	2010	811,220	0	2,484,440	0	2,907,853	1,285,224	4,193,869	11,682,606
S. Bradford Rives Chief Financial Officer	2010	414,215	0	704,585	0	1,230,600	515,207	975,105	3,839,712
John R. McCall EVP, General Counsel, Corporate Secretary and Chief Compliance Officer	2010	507,674	0	888,913	0	1,508,275	191,020	1,523,236	4,619,118
Chris Hermann SVP—Energy Delivery	2010	326,102	0	538,018	0	965,125	184,417	611,200	2,624,862
Paul W. Thompson SVP—Energy Services	2010	386,624	0	657,496	0	1,148,700	499,932	920,959	3,613,711

(1): The Stock Awards column represents the aggregate grant date fair value as calculated under ASC Topic 718, without taking into account estimated forfeitures, and reflects 2010 grants of PPL restricted stock units and E.ON share performance rights. Vesting of the E.ON share performance rights accelerated upon the November 1, 2010 change in control, and the amounts paid in cash to the named executive officers are included in the All Other Compensation column. For additional information on the assumptions in the valuation, see the Grants of Plan-Based Awards During 2010 table below.
(2): Non-Equity Incentive Plan Compensation represents payments of the E.ON AG divestiture incentive award tied to the change in control and payments made in 2011 under the Powergen Short Term Incentive Plan for performance under that annual cash incentive program in 2010.
(3): This column represents the sum of the changes in the present value of the accumulated benefit in the E.ON U.S. LLC Retirement Plan and the LG&E Energy Corp. Supplemental Executive Retirement Plan from December 31, 2009 to December 31, 2010.
(4)

All Other Compensation in 2010

Name

Staffieri	10,290	53,118	4,028,253	11,620	1,898	1,680	7,200	150	15,710		6,000	7,574	3,500	12,480	34,396
Rives	10,290	17,271	922,210	11,472	1,892	1,680	50	150	592						9,498
McCall	10,290	23,666	1,413,008	11,836	1,466	1,680		150	29,255	(e)	8,000	3,577	1,500		18,808
Hermann	10,290	11,603	544,298	5,921	4,035	1,680		150	8,682		5,583		1,750	4,871	12,337
Thompson	10,290	15,432	860,806	11,083		1,680		150	3,358		4,028		2,021		12,111

(c): Personal usage of executive auto. The named executive officers receive an annual $15,000 allowance to cover auto lease expenses, and any difference between the annual allowance and the total lease cost is paid in cash to them.
(d): Premiums paid by our Parent for $2 million of supplemental executive term life insurance for Mr. Staffieri and $400,000 for the other named executive officers, except for Mr. McCall.
(e): Prior to 2010, Mr. McCall waived future coverage for executive life insurance. A fixed cash payment is made each October in lieu of executive life insurance and applies for the duration of his employment.
(f): Occasionally, an executive's spouse may accompany the executive on a business trip. In 2010, Messrs. Staffieri's and McCall's spouses accompanied them on business trips. The dollar amounts reflected in the table are the standard industry fare level values, which were greater than the aggregate incremental cost, which was de minimis.
(g): Our Parent paid a full tax gross-up to executives for additional tax expenses in connection with personal usage of executive auto, auto lease allowance cash difference, country/luncheon club membership, tax preparation fees and financial planning services and spousal air travel, and for Mr. Staffieri, life insurance benefits.



						LG&E Energy Corp. Long- Term Performance Unit: Number of Units (#)															All Other Option Awards: Number of Securities Underlying Options (#) (j)
								Estimated Possible Payouts Under Non- Equity Incentive Plan Awards						Estimated Possible Payouts Under Equity Incentive Plan Awards									Grant Date Fair Value of Stock and Option Awards (6) (l)
																						Exercise or Base Price of Option Awards ($/sh) (k)
				Board or Committee Approval Date
Name (a)	Grant Date (b)			Board or Committee Approval Date				Threshold ($) (c)		Target ($) (d)		Maximum ($) (e)		Threshold ($) (f)		Target ($) (g)		Maximum ($) (h)
Staffieri		3/3/10	(1)						23,619		608,415		1,216,830
		4/16/10	(2)				1,064,726		809,192		1,064,726		1,597,089
		4/16/10	(3)		3/3/10										17,745		354,909		1,064,727					354,909
		11/1/10	(4)		10/21/10															80,940				2,129,531
Rives		3/3/10	(1)						8,286		207,200		414,400
		4/16/10	(2)				248,640		188,966		248,640		372,960
		4/16/10	(3)		3/3/10										4,144		82,880		248,640					82,880
		11/1/10	(5)																	23,630				621,705
McCall		3/3/10	(1)						10,155		253,950		507,900
		4/16/10	(2)				380,925		289,503		380,925		571,388
		4/16/10	(3)		3/3/10										6,349		126,975		380,925					126,975
		11/1/10	(5)																	28,960				761,938
Hermann		3/3/10	(1)						6,520		163,050		326,100
		4/16/10	(2)				146,745		111,526		146,745		220,118
		4/16/10	(3)		3/3/10										2,446		48,915		146,745					48,915
		11/1/10	(5)																	18,590				489,103
Thompson		3/3/10	(1)						7,735		193,400		386,800
		4/16/10	(2)				232,080		176,381		232,080		348,120
		4/16/10	(3)		3/3/10										3,868		77,360		232,080					77,360
		11/1/10	(5)																	22,050				580,136

(1): Short-term cash incentive awards granted under the Powergen Short-Term Incentive Plan. The amounts reported reflect the potential payout range from a threshold of approximately four percent of target to a maximum of 200 percent of target. Threshold amounts are based on threshold performance on objective measures and exclude subjective measures. Payouts for percentile ranks falling between threshold and target and between target and maximum are interpolated. The actual 2010 payout is included in the Summary Compensation Table in the column headed "Non-Equity Incentive Plan Compensation."
(2): Performance unit awards payable in cash for the 2010-2012 performance cycle granted under the LG&E Energy Corp. Long-Term Performance Unit Plan. The amounts reported reflect the potential payout range from a threshold of 50 percent of target to a maximum of 150 percent of target. Performance below 76 percent of target yields 0 percent payout. Vesting of these awards accelerated upon the November 1, 2010 change in control, and the dollar amounts paid are included in the Summary Compensation Table in the column headed "All Other Compensation."
(3): Share performance rights for the 2010-2013 performance cycle granted under the E.ON Share Performance Plan on April 16, 2010 for purposes of Financial Accounting Standards Board generally accepted accounting principles for stock-based compensation. The E.ON AG Board of Management approved these awards on March 3, 2010. Vesting of these awards accelerated upon the November 1, 2010 change in control, and the dollar amounts paid are included in the Summary Compensation Table in the column headed "All Other Compensation" and in the Option Exercises and Stock Vested table in the column headed "Value Realized on Vesting."
(4): Restricted stock units granted under the PPL Incentive Compensation Plan on November 1, 2010 for purposes of Financial Accounting Standards Board generally accepted accounting principles for stock-based compensation. The PPL Compensation, Governance and Nominating Committee approved these awards on October 21, 2010.
(5): Restricted stock units granted under the PPL Incentive Compensation Plan for Key Employees on November 1, 2010 for purposes of Financial Accounting Standards Board generally accepted accounting principles for stock-based compensation.
(6): This column shows the full grant date fair value, as calculated under ASC Topic 718, of share performance rights and restricted stock units granted to the named executive officers, without taking into account estimated forfeitures. For restricted stock units granted by PPL, the grant date fair value was calculated using the closing price of PPL stock on the New York Stock Exchange on the November 1, 2010 grant date of $26.31. The named executive officers receive cash dividend-equivalents during the period of restriction that are not subject to forfeiture. For share performance rights granted by E.ON AG on April 16, 2010, the grant date fair value was calculated using the initial E.ON AG share price of €27.25, which was the arithmetic mean of the E.ON stock's closing prices, as determined and published by the Deutsche Börse AG in the XETRA (Exchange Electronic Trading) system during the 60 trading days prior to the beginning of the maturity period, January 1, 2010. The Euro share price was multiplied by the initial exchange rate of 1.4803 which represents the average exchange rate for the 60 trading days preceding the beginning of the maturity period; the US$ share price was calculated at $40.34. The maximum amount payable is three times the initial E.ON AG share price, or €81.75.

Narrative Discussion Relating to the Summary Compensation Table and the Grants of Plan-Based Awards Table

In March 2010, short-term incentive award opportunities were granted to the named executive officers under the Powergen Short-Term Incentive Plan. These award opportunities are reflected in the Grants of Plan-Based Awards table at grant in columns (c), (d) and (e) and in the Summary Compensation Table as earned with respect to 2010 in column (g). We discuss the short-term incentive award opportunities, incentive goals and results in the Compensation Discussion and Analysis.

We describe these long-term incentive awards in the Compensation Discussion and Analysis.

Accelerated Payment of Outstanding Long-Term Incentive Awards Granted in 2008, 2009 and 2010 upon Change in Control

Outstanding long-term incentive awards granted in 2008, 2009 and 2010 vested and were paid out as a result of the November 1, 2010 change in control as described in the Compensation Discussion and Analysis.

In 2008, the E.ON AG Board of Management granted an incentive award opportunity to the named executive officers in connection with the consummation of a change in control of our Parent. We describe these divestiture incentive awards in the Compensation Discussion and Analysis.

As previously stated, PPL granted restricted stock units to Mr. Staffieri under the PPL Incentive Compensation Plan and to the other named executive officers under the PPL Incentive Compensation Plan for Key Employees. These award opportunities are reflected in the Grants of Plan-Based Awards table at grant in columns (i) and (l) and in the Summary Compensation Table in column (e). We discuss the restricted stock unit awards in the Compensation Discussion and Analysis.

In October 2010, our Parent entered into amended and restated employment and severance agreements with Messrs. Staffieri and McCall that replace previous agreements, dated February 25, 2000, as amended, with LG&E Energy Corporation and Powergen plc. The other named executive officers also entered into retention and severance agreements in October 2010 that replace previous agreements with LG&E Energy Corp. and E.ON AG. We discuss the named executive officers' agreements in the Compensation Discussion and Analysis and in the Employment-Related Arrangements section.

The named executive officers did not receive any bonuses. The proportion of salary to compensation is reflected in the table below.

The following table provides information on all unvested restricted stock unit awards for each named executive officer as of December 31, 2010. The Option Awards columns have been omitted because there were no stock option awards outstanding as of December 31, 2010.

The following table provides information for each of the named executive officers with respect to payments from the E.ON Share Performance Plan for grants made in 2007 that vested in January 2010 and grants made in 2008, 2009 and 2010 that vested at the November 1, 2010 change in control. Value reflects payment in the aggregate before applicable withholding tax.

(1): Reflects vesting of share performance rights for the 2007-2009 performance period that vested on January 5, 2010 and share performance rights granted in 2008, 2009 and 2010 for which vesting was accelerated upon the November 1, 2010 change in control. All awards were paid in cash.
(2): Reflects the actual cash value of share performance rights that the named executive officers realized upon vesting. The value realized with respect to the share performance rights granted in 2007 was based on an E.ON AG stock price of $121.02, which was the average closing stock price for the 60 trading days preceding the end of the 2007-2009 performance period, as adjusted. Values were provided by HSBC Trinkaus in Euros and converted to US currency using the average exchange rate for the 60 trading days preceding the end of the performance period. E.ON AG effected a 3-for-1 stock split, effective August 1, 2008. While the share performance rights were not adjusted for the split, in determining payment, the average closing value was calculated and then adjusted by HSBC Trinkaus to give effect to the stock split.

The value realized with respect to share performance rights granted in 2008, 2009 and 2010 was based on an E.ON AG stock price of $29.64, which was the average closing stock price for the 60 trading days preceding the change in control. Values were provided by HSBC Trinkaus in Euros and converted to US currency using the average exchange rate for the 60 trading days preceding the change in control.

The following table sets forth information on the pension benefits for the named executive officers:

Name (a)	Plan Name (b)(1)

Staffieri	Retirement	18.75	693,309	0
	SERP	18.75	7,645,065	0
Rives	Retirement	26.83	819,226	0
	SERP	27.83	2,034,524	0
McCall	Retirement	16.50	767,610	0
	SERP	16.50	4,426,391	0
Hermann	Retirement	30.00	1,532,112	0
	SERP	30.00	2,047,683	0
Thompson	Retirement	19.75	657,499	0
	SERP	19.75	2,218,154	0

The amounts shown for the retirement plan and the SERP represent the actuarial present values of the executives' accumulated benefits accrued as of December 31, 2010, calculated using a 5.52 percent discount rate for the retirement plan and a 5.46 percent discount rate for the SERP, the mortality table used for 2011 Pension Protection Act target liability purposes as prescribed by the Internal Revenue Service for December 31, 2010 present values for post retirement mortality rates and no recognition of future salary increases or pre-retirement mortality. The assumed retirement age for these benefits was age 62 for Messrs. Staffieri, Rives and Thompson. Retirement on December 31, 2010 was assumed for Messrs. McCall and Hermann, who were age 67 and 63, respectively, on that date. Benefits were also assumed to be paid as life annuities. While Mr. Hermann has over 40 years of actual service with us, his years of credited service are capped at 30 in accordance with the provisions of the E.ON U.S. LLC Retirement Plan.

Messrs. Staffieri, Rives, McCall, Hermann and Thompson participate in the E.ON U.S. LLC Retirement Plan. The plan is a funded and tax-qualified defined benefit retirement plan that was closed to new participants on December 31, 2005. The purpose of the plan is to provide all vested eligible employees with retirement income. Vesting occurs after completing five years of service. The named executive officers are vested under the plan.

The maximum years of service recognized when determining benefits under the plan is 30.

For purposes of the plan, average monthly earnings is the average of the highest five consecutive monthly earnings prior to termination of employment. Monthly earnings is defined as total compensation as indicated on Form W-2, including deferrals to a 401(k) plan, but excluding any earnings from the exercise of stock options, divided by 12.

Covered compensation is one-twelfth of the average of the social security taxable wage base for the 35-year period ending with the year of a participant's social security retirement age. The social security taxable wage base for future years is assumed to be equal to the social security taxable wage base for the current year.

The Internal Revenue Code limits the amounts that may be paid under the plan and the amount of compensation that may be recognized when determining benefits. In 2010, the maximum annual benefit payable under the plan was $195,000, and the maximum amount of compensation that could be recognized when determining benefits was $245,000.

Normal retirement age is age 65, and Mr. McCall was eligible for normal retirement on December 31, 2010. Early retirement occurs at the earlier of age 55 or 30 years of credited service, and Messrs. Staffieri and Hermann were eligible for early retirement on December 31, 2010. To receive unreduced retirement benefits under the plan, participants must remain employed until age 62, and Mr. Hermann was eligible for unreduced benefits on December 31, 2010. Participants who elect to retire before reaching age 62 receive benefits under the plan calculated as follows:

Messrs. Staffieri, Rives, McCall, Hermann and Thompson participate in the SERP, which is a non-qualified defined benefit pension plan. The SERP is unfunded and is not qualified for tax purposes. Accrued benefits under the SERP are subject to claims of our creditors in the event of bankruptcy. The purpose of the SERP is to provide additional retirement income to selected executives.

Upon a separation from service occurring on or after the participant attains age 65, participants are entitled to monthly retirement income equal to 64 percent of average monthly compensation less:

Such amount is multiplied by a fraction not to exceed "1", the numerator of which is years of service at date of separation from service and the denominator of which is 15.

Average monthly compensation is the average compensation for the 36 consecutive months preceding the participant's separation from service that yields the highest average. Compensation is defined as base salary plus short term incentive pay prior to any deferrals under any qualified or non-qualified deferred compensation plan.

Normal retirement age is 65, and Mr. McCall was eligible for normal retirement on December 31, 2010. A participant who has at least five years of credited service and whose age is at least 50 is eligible to receive early retirement benefits after the later of separation from service and the date the participant attains age 55. Messrs. Staffieri and Hermann were eligible for early retirement on December 31, 2010. To receive unreduced benefits under the SERP, participants must remain employed until age 62, and Mr. Hermann was eligible for unreduced benefits on December 31, 2010. Participants electing to retire before reaching age 62 receive benefits under the SERP calculated as follows:

Benefits under the SERP are paid as a single life annuity unless the participant dies before benefits commence or the participant elects to receive actuarial equivalent payments in the form of a joint and survivor annuity. The joint and survivor annuity provides a reduced monthly benefit payable for the life of the participant that will continue to be made in an amount equal to 50 percent of the participant's benefit to a beneficiary designated by the participant.

The present values in the Pension Benefits for 2010 table are theoretical figures prescribed by the SEC for disclosure and comparison purposes. The table below reflects the actual benefits payable under the listed events assuming separation from service occurred as of December 31, 2010.

(1): If Mr. Staffieri separated from service, for reasons other than due to death or disability, on December 31, 2010 and commenced his SERP benefit on January 1, 2011, the monthly benefit payable as a life annuity is $48,297. If he had died on December 31, 2010, the monthly SERP benefit payable to his spouse for her lifetime on January 1, 2011 is $36,588. If Mr. Staffieri had become disabled on December 31, 2010, the monthly SERP disability benefit payable at age 65 as a life annuity, assuming continued accrual, is $69,321.
(2): If Mr. Rives separated from service, for reasons other than due to death or disability, on December 31, 2010 and commenced his SERP benefit at age 55, the monthly benefit payable as a life annuity is $14,479. If he had died on December 31, 2010, the monthly SERP benefit payable to his spouse for her lifetime on January 1, 2011 is $11,676. If Mr. Rives had become disabled on December 31, 2010, the monthly SERP disability benefit payable at age 65 as a life annuity, assuming continued accrual, is $21,859.
(3): If Mr. McCall separated from service, for reasons other than due to death or disability, on December 31, 2010 and commenced his SERP benefit on January 1, 2011, the monthly benefit payable as a life annuity is $34,627. If he had died on December 31, 2010, the monthly SERP benefit payable to his spouse for her lifetime on January 1, 2011 is $17,313. If Mr. McCall had become disabled on December 31, 2010, the monthly SERP disability benefit payable at January 1, 2011 as a life annuity is $34,627.
(4): If Mr. Hermann separated from service, for reasons other than due to death or disability, on December 31, 2010 and commenced his SERP benefit on January 1, 2011, the monthly benefit payable as a life annuity is $14,446. If he had died on December 31, 2010, the monthly SERP benefit payable to his spouse for her lifetime on January 1, 2011 is $7,223. If Mr. Hermann had become disabled on December 31, 2010, the monthly SERP disability benefit payable at age 65 as a life annuity, assuming continued accrual, is $14,198.
(5): If Mr. Thompson separated from service, for reasons other than due to death or disability, on December 31, 2010 and commenced his SERP benefit at age 55, the monthly benefit payable as a life annuity is $14,511. If he had died on December 31, 2010, the monthly SERP benefit payable to his spouse for her lifetime on January 1, 2011 is $11,703. If Mr. Thompson had become disabled on December 31, 2010, the monthly SERP disability benefit payable at age 65 as a life annuity, assuming continued accrual, is $19,318.

Name (a)

Staffieri
	E.ON U.S. NQSP	82,345	53,118	22,729	145,025	(2)	762,230
	LG&E Energy Corp. NQSP	0	0	29,663	0		928,850
Rives
	E.ON U.S. NQSP	45,339	17,271	11,096	0		374,232
	LG&E Energy Corp. NQSP	0	0	40,872	0		1,279,849
McCall
	E.ON U.S. NQSP	117,218	23,666	26,615	0		896,195
	LG&E Energy Corp. NQSP	0	0	45,560	0		1,426,646
Hermann
	E.ON U.S. NQSP	28,062	11,603	7,580	0		256,540
	LG&E Energy Corp. NQSP	0	0	19,391	0		607,188
Thompson
	E.ON U.S. NQSP	55,466	15,432	23,022	0		753,620
	LG&E Energy Corp. NQSP	0	0	45,297	0		1,418,424

Messrs. Staffieri, Rives, McCall, Hermann and Thompson participate in the E.ON U.S. LLC Nonqualified Savings Plan, which we refer to as the E.ON U.S. plan, and the LG&E Energy Corp. Nonqualified Savings Plan, which we refer to as the LG&E Energy plan. Both plans are non-qualified, unfunded deferred compensation plans, and all benefits under the plans are subject to the claims of creditors in the event of bankruptcy. The LG&E Energy plan benefits are limited to the contributions credited to the participants' plan accounts as of December 31, 2004 and interest accruing on those accounts. Executives are no longer permitted to defer income under the LG&E Energy plan. The E.ON U.S. plan benefits are based on contributions made and interest accruing on those contributions after December 31, 2004 and are subject to Section 409A of the Internal Revenue Code.

The E.ON U.S. plan provides executives with an opportunity to defer income on a tax-deferred basis in addition to deferrals under the tax-qualified savings plan. Executives may participate in the E.ON U.S. plan after the later of promotion to an executive position and the completion of six months of continuous employment.

A hypothetical account is established for each participant who elects to defer compensation. Under the E.ON U.S. plan, executives may elect to defer up to 75 percent of their eligible compensation, which includes base pay and short-term incentive pay. This amount is reduced by any amount deferred and subject to an employer match under the tax-qualified savings plan. Participants in the plan receive a matching contribution equal to 70 percent of the first six percent deferred.

Participants are immediately vested in their deferrals and employer matching contributions.

The amounts in the participant's hypothetical accounts in the E.ON U.S. plan and the LG&E Energy plan are credited with interest at an annual rate equal to the U.S. prime interest rate reset as of the immediately preceding March 31, June 30, September 30 and December 31. The interest rate in effect for 2010 was 3.25 percent.

All distributions are made in cash. Participants may choose whether distributions will be made in a lump sum or in two to ten annual installments. In general, distributions under the E.ON U.S. plan are made at the time specified by the named executive officer at the time of completion of the deferral election. However, a "hardship distribution" will be approved if there is an unforeseeable emergency, as defined by Section 409A, that causes a severe financial hardship to the participant.

A participant is eligible to receive a distribution under the LG&E Energy plan upon termination of employment.

In connection with PPL's acquisition of our Parent's, our Parent entered into amended and restated employment and severance agreements with Messrs. Staffieri and McCall in October 2010 that replaced previous agreements, dated February 25, 2000, as amended, with LG&E Energy Corporation and Powergen plc. The agreements provide severance, change in control protection and other benefits substantially similar to those in the previous agreements. The agreements provide for changes needed to reflect the change in control, Messrs. Staffieri's and McCall's retention with our Parent and their anticipated roles after the change in control.

The employment and severance agreements have an initial two-year term beginning November 1, 2010, with automatic one-year extensions, unless our Parent or any subsidiary of our Parent gives 90 days notice that the agreements will not be extended. Under the terms of their agreements, Mr. Staffieri and Mr. McCall are entitled to:

If, within two years following our Parent's acquisition by PPL or a future change in control, excluding a change in control of PPL, the executive's employment is terminated by the executive for good reason or by our Parent for reasons other than cause, disability or death, which includes notice by our Parent not to extend the term of the agreement, the executive would be entitled to:

If Mr. Staffieri's or Mr. McCall's employment is terminated at any other time by the executive for good reason or by our Parent for reasons other than cause, disability or death, which includes notice by our Parent not to extend the term of the agreement, he would be entitled to:

Termination for cause is defined as a termination evidenced by a resolution approved by at least 75 percent of our Parent's board that the executive has engaged in repeated willful misconduct in performing his reasonably assigned duties or has been convicted of a felony in the course of performing such duties.

The executive may not terminate his employment for good reason, unless he has provided notice, within 90 days of the occurrence of any of these actions, to our Parent or its subsidiary and it has failed to cure such circumstances within a period of at least 30 days.

If the executive's employment is terminated due to death or disability, he will be entitled to:

In 2010, our Parent entered into retention and severance agreements with Messrs. Rives, Hermann and Thompson that replace previous change in control agreements and retention and severance agreements with LG&E Energy Corp. and E.ON AG. The agreements provide severance, change in control protection and other benefits substantially similar to those in the previous agreements.

The retention and severance agreements have an initial two-year term beginning November 1, 2010, with automatic one-year extensions, unless our Parent or any subsidiary of our Parent gives 90 days notice that the agreements will not be extended. Under the terms of these agreements, the executives are entitled to receive a retention agreement and a divestiture incentive award payment of

$932,400 for Mr. Rives, $733,725 for Mr. Hermann and $870,300 for Mr. Thompson, which were paid upon closing of the change in control.

If, within two years following the acquisition by PPL or a future change in control, excluding a change in control of PPL, the executive's employment is terminated by the executive for good reason or by our Parent for reasons other than cause, disability or death, the executive would be entitled to:

If employment is terminated at any other time by the executive for good reason or by our Parent for reasons other than cause, disability or death, the executive would be entitled to:

Termination for cause is defined as a termination evidenced by a resolution approved by at least 75 percent of our Parent's board that the executive has engaged in repeated gross negligence in performing his reasonably assigned duties or has committed a felony in the course of performing such duties.

The executive may not terminate his employment for good reason, unless he has provided notice, within 90 days of the occurrence of any of these actions, and our Parent or its subsidiary failed to cure such circumstances within a period of not less than 30 days.

The definition of change in control for these executives' agreements is the same as that contained in Messrs. Staffieri's and McCall's employment and severance agreements, which we describe above.

to forfeiture. In his retention agreement, Mr. Staffieri also agreed to modify the perquisites he received pursuant to his employment and severance agreement and gave up an employer-paid country club membership and company-paid use of air transportation for any non-business purpose, as well as, effective January 1, 2011, tax gross-up payments on his perquisites. PPL entered into the retention agreements to encourage the named executive officers to remain employed by PPL or an affiliated company and to compensate Mr. Staffieri for the loss of these perquisites.

See the Compensation Discussion and Analysis for the number of restricted stock units granted, the grant date fair value and the vesting date of the awards.

The following table shows the payments and benefits our named executive officers would receive in connection with:

If a named executive officer is terminated for cause, no additional benefits or payments are due to the named executive officer.

The information assumes the terminations and the change in control occurred on December 31, 2010. The values for the restricted stock units were determined by multiplying the number of units that vest by $26.32, which was the closing price of PPL common stock on December 31, 2010.

The table does not include base salary and short-term incentive awards, to the extent earned due to employment through December 31, 2010. The table excludes compensation and benefits provided under plans or arrangements that do not discriminate in favor of the named executive officers and that are generally available to all salaried employees. Because the amounts payable to the named executive officers would not constitute excess parachute payments under Internal Revenue Code Section 280G that trigger excise taxes under Internal Revenue Code Section 4999, the table does not include any tax gross-up payments for the named executive officers. The table also excludes the named executive officers' benefits under the E.ON U.S. LLC Retirement Plan, the LG&E Energy Corp. Supplemental Executive Retirement Plan, the E.ON U.S. LLC Nonqualified Savings Plan and the LG&E Energy Corp. Nonqualified Savings Plan. See the Pension Benefits in 2010 table and the Nonqualified Deferred Compensation in 2010 table, and accompanying narratives, for a description of the named executive officers' accumulated benefits under our defined benefit pension plans and our nonqualified deferred compensation plans.

For additional information regarding the termination-related payments and benefits provided by Messrs. Staffieri's and McCall's employment and severance agreements and the other named executive

officers' retention and severance agreements, please refer to the Employment-Related Arrangements section.

Name

Staffieri
	Severance payable in cash		0	0		0		4,752,964	(1)
	Other separation benefits		0	48,420	(3)	0	(4)	207,535	(2)
	Restricted stock units		0	88,764	(5)	88,764	(5)	0

		Total	0	137,184		88,764		4,960,499
Rives
	Severance payable in cash		0	0		0		1,858,584	(1)
	Other separation benefits		0	0		0		111,874	(2)
	Restricted stock units		0	25,914	(5)	25,914	(5)	0

		Total	0	25,914		25,914		1,970,458
McCall
	Severance payable in cash		0	0		0		2,611,466	(1)
	Other separation benefits		0	365,500	(6)	365,500	(6)	144,351	(2)
	Restricted stock units		0	63,519	(5)	63,519	(5)	0

		Total	0	429,019		429,019		2,755,817
Hermann
	Severance payable in cash		0	0		0		1,462,559	(1)
	Other separation benefits		0	0		0		84,896	(2)
	Restricted stock units		0	20,387	(5)	20,387	(5)	0

		Total	0	20,387		20,387		1,547,455
Thompson
	Severance payable in cash		0	0		0		1,734,798	(1)
	Other separation benefits		0	0		0		106,354	(2)
	Restricted stock units		0	24,182	(5)	24,182	(5)	0

		Total	0	24,182		24,182		1,841,152

(1): Each of the named executive officers has an employment and severance agreement, or a retention and severance agreement, with our Parent under which he is entitled to cash severance equal to 2.99 times base salary and short-term incentive if employment is terminated by us for any reason other than for cause or by the executive for "good reason" as that term is defined in his agreement. For Mr. Staffieri and Mr. McCall, the short-term incentive amount used for determining the cash severance amount was the actual 2010 short-term incentive payment. For the other named executive officers, the short-term incentive amount reflects 2010 target short-term incentive, in accordance with their agreements.
(2): Under the terms of each named executive officer's severance agreement, the executive is eligible for continued medical and dental benefits, life insurance premiums, disability coverage and outplacement services. The amounts shown as "Other separation benefits" are the estimated present values of these benefits.
(3): If Mr. Staffieri's employment is terminated as a result of death, for a period of 36 months, our Parent would at its expense continue on behalf of Mr. Staffieri's dependents and beneficiaries (to the same extent provided to the dependents and beneficiaries prior to his death) the life insurance,

medical, dental and hospitalization benefits under such plans offered by our Parent to active employees.

(4): If Mr. Staffieri's employment is terminated as a result of disability, he would receive until age 65 a benefit equal to 60 percent of his base salary, less 100 percent of the social security disability benefit and any amounts payable pursuant to the terms of a disability insurance policy or similar arrangement which our Parent maintains during the term. It is anticipated that the disability insurance policy would cover this payment in full and thus there would not be an additional payment.
(5): Restricted stock units granted to each named executive officer pursuant to his Retention Agreement would be prorated for completed months employed during the one year vesting schedule for Mr. McCall (December 1, 2010—December 1, 2011) or the two year vesting schedule for the other named executive officers (December 1, 2010—December 1, 2012). Thus the values shown in the table above reflect 1/12th the value of Mr. McCall's full award and 1/24th the value of the other named executive officers' full awards as of December 31, 2010. The value was determined based on the closing price of PPL common stock on the New York Stock Exchange of $26.32 on December 31, 2010.
(6): If Mr. McCall's employment is terminated as a result of death or disability, he would receive a cash payment equal to his 2010 short-term incentive payment.

The board of directors consists of the named executive officers, as well as Paul A. Farr, PPL executive vice president and chief financial officer, and William H. Spence, PPL executive vice president and chief operating officer. The directors received no compensation for board service.

Narrative Disclosure of our Compensation Policies and Practices
as They Relate to Risk Management

Our senior management has reviewed our policies and practices of compensating our employees, including the non-executive officers, as they relate to risk management practices and risk-taking incentives. The senior management reviewed a description of the types of risks that may exist in certain compensation arrangements, each component of compensation for employees, the mix of fixed and "at-risk" incentive compensation and the goals used for incentive compensation, in addition to considering the risk profile of our business. Based upon this review, we concluded that our compensation policies and practices for all our employees do not create risks that are reasonably likely to have a material adverse effect on us.

We are wholly owned by our Parent, and our board of directors is comprised solely of our five named executive officers and two executive officers of PPL. We have no compensation committee or other board committee performing equivalent functions. Prior to the acquisition, as discussed in the Compensation Discussion and Analysis, the E.ON AG Board of Management set compensation for our named executive officers. The E.ON AG Board of Management consulted with Mr. Staffieri as well as with the E.ON AG chairman of the board, chief executive officer and president and the E.ON AG senior vice president of group corporate officer resources in setting compensation. After the acquisition, the PPL Compensation, Governance and Nominating Committee, a committee of independent directors, assumed oversight of Mr. Staffieri's compensation. Compensation for the other named executive officers after the acquisition was reviewed by the PPL vice president-human resources and services, the PPL chief executive officer and the PPL Corporate Leadership Council.

We have in place a number of established policies and procedures to identify potential conflicts of interest arising out of financial transactions, arrangements or relations between the Company and any related persons. The conflict of interest provisions of our Code of Business Conduct and/or applicable principles and personnel provisions of its Authority Limits Policy apply to any transaction in which the Company or a subsidiary is a participant and covered persons has a direct or indirect material interest. A covered person includes not only our directors and executive officers, but others related to them by certain family relationships. Employees of the Company who are also executive officers of PPL are also covered under PPL's related-person policy.

Under our policies and procedures, each such related-person transaction must be reviewed and approved or ratified by the General Counsel, other than any personnel matters or transaction involving an officer, which must be approved by the Chairman and a designated PPL officer. We collect information about potential related-person transactions in annual questionnaires completed by directors and executive officers. Transactions involving non-compliance with established polices are reported to the Board, as applicable. The Board can review and consider the relevant facts and circumstances and determine whether to approve, deny or ratify the related-person transaction. Transactions falling within the definition of PPL's related-party policy are further reviewed by PPL's Office of General Counsel for determination as to reporting to PPL's Board or its Compensation, Governance and Nominating Committee, as applicable.

No event has occurred since January 1, 2010 that would be required to be reported by the Company pursuant to Item 404(a) of Regulation S-K promulgated by the SEC.

The Outstanding Bonds were issued on November 16, 2010 and sold to the initial purchasers pursuant to a purchase agreement in transactions not requiring registration under the Securities Act. The initial purchasers subsequently sold the Outstanding Bonds to qualified institutional buyers (as defined in Rule 144A under the Securities Act) in reliance on Rule 144A, and to persons in offshore transactions in reliance on Regulation S under the Securities Act.

We entered into a registration rights agreement with representatives of the initial purchasers of the Outstanding Bonds in which we agreed, under certain circumstances, to file a registration statement relating to offers to exchange the Outstanding Bonds for Exchange Bonds and to use commercially reasonable efforts to cause such registration statement to be declared effective under the Securities Act no later than 270 days after the original issue date of the Outstanding Bonds and to pay liquidated damages as described below if we do not consummate the Exchange Offers within 315 days after the issue date of the Outstanding Bonds. The Exchange Bonds will have terms identical in all material respects to the Outstanding Bonds of the related series, except that the Exchange Bonds will not contain certain terms with respect to transfer restrictions, registration rights and liquidated damages for failure to observe certain obligations in the registration rights agreement.

Under the circumstances set forth below, we will use commercially reasonable efforts to cause the SEC to declare effective a shelf registration statement with respect to the resale of the Outstanding Bonds within the time periods specified in the registration rights agreement and keep the statement effective for one year from the original issue date of the Outstanding Bonds, or such shorter period as described in the registration rights agreement. These circumstances include:

Except for certain circumstances specified in the registration rights agreement, we will pay liquidated damages if:

We sometimes refer to an event referred to in the first through fourth bullet items above as a Registration Default.

Liquidated damages, if payable, will be payable on the Outstanding Bonds at a rate of 0.25% per annum for the first 90 days from and including the date on which any Registration Default occurs, and such liquidated damages rate shall increase by an additional 0.25% per annum thereafter; provided, however, that the liquidated damages rate on the Outstanding Bonds will not at any time exceed 0.50% per annum. Liquidated damages will cease to accrue on and after the date on which all Registration Defaults have been cured. Any such liquidated damages payable will be payable on interest payment dates in addition to interest payable from time to time on the Outstanding Bonds and Exchange Bonds.

If you wish to exchange your Outstanding Bonds for Exchange Bonds in any of the Exchange Offers, you will be required to make the following written representations:

Each broker-dealer that receives Exchange Bonds for its own account in exchange for Outstanding Bonds, where the broker-dealer acquired the Outstanding Bonds as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Bonds and that it did not purchase its Outstanding Bonds from us or any of our affiliates. See "Plan of Distribution."

We have not requested, and do not intend to request, an interpretation by the staff of the SEC as to whether the Exchange Bonds issued pursuant to this Exchange Offer in exchange for the Outstanding Bonds may be offered for sale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Instead, based on interpretations by the SEC set forth in no-action letters issued to third parties, we believe that you may resell or otherwise transfer Exchange Bonds issued in the Exchange Offers without complying with the registration and prospectus delivery provisions of the Securities Act if:

If you are our affiliate, or are engaging in, or intend to engage in, or have any arrangement or understanding with any person to participate in, a distribution of the Exchange Bonds, or are not acquiring the Exchange Bonds in the ordinary course of your business:

This prospectus may be used for an offer to resell or transfer the Exchange Bonds only as specifically set forth in this prospectus. With regard to broker-dealers, only broker-dealers that acquired the Outstanding Bonds as a result of market-making activities or other trading activities may participate in the Exchange Offers. Each broker-dealer that receives Exchange Bonds for its own account in exchange for Outstanding Bonds, where such Outstanding Bonds were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the Exchange Bonds. Read "Plan of Distribution" for more details regarding the transfer of Exchange Bonds.

Our belief that the Exchange Bonds may be offered for resale without compliance with the registration or prospectus delivery provisions of the Securities Act is based on interpretations of the SEC for other exchange offers that the SEC expressed in some of its no-action letters to other issuers in exchange offers like ours. We have not sought a no-action letter in connection with the Exchange Offers, and we cannot guarantee that the SEC would make a similar decision about our Exchange Offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any Exchange Bond issued to you in the Exchange Offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. We are not indemnifying you for any such liability.

On the terms and subject to the conditions set forth in this prospectus and in the accompanying letters of transmittal, we will accept for exchange in the Exchange Offers any Outstanding Bonds that are validly tendered and not validly withdrawn prior to the Expiration Date. Outstanding Bonds may only be tendered in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $2,000, and any untendered Outstanding Bonds must also be in a minimum denomination of $2,000. We will issue Exchange Bonds in principal amount identical to Outstanding Bonds surrendered in the Exchange Offers.

The form and terms of the Exchange Bonds will be identical in all material respects to the form and terms of the Outstanding Bonds of the related series except the Exchange Bonds will be registered under the Securities Act, will not bear legends restricting their transfer and will not provide for any payment of liquidated damages upon our failure to fulfill our obligations under the registration rights agreement to complete the Exchange Offers, or file, and cause to be effective, a shelf registration statement, if required thereby, within the specified time period. The Exchange Bonds will evidence the same debt as the Outstanding Bonds of the related series. The Exchange Bonds will be issued under and entitled to the benefits of the Indenture. For a description of the Indenture, see "Description of the Exchange Bonds."

No interest will be paid in connection with the exchange. The Exchange Bonds will bear interest from the last Interest Payment Date (as defined under "Description of the Exchange Bonds—Maturity; Interest") on the Outstanding Bonds surrendered in the Exchange Offers. Accordingly, the holders of Outstanding Bonds that are accepted for exchange will not receive accrued but unpaid interest on Outstanding Bonds at the time of tender. Rather, that interest will be payable on the Exchange Bonds delivered in exchange for the Outstanding Bonds on the first Interest Payment Date after the Expiration Date (as defined below under "—Expiration Date, Extensions and Amendments").

The Exchange Offers are not conditioned upon any minimum aggregate principal amount of Outstanding Bonds being tendered for exchange.

As of the date of this prospectus, $250 million aggregate principal amount of the 1.625% First Mortgage Bonds due 2015 and $285 million aggregate principal amount of the 5.125% First Mortgage Bonds due 2040 are outstanding. This prospectus and the letters of transmittal are being sent to all registered holders of Outstanding Bonds. There will be no fixed record date for determining registered holders of Outstanding Bonds entitled to participate in the Exchange Offers. We intend to conduct the Exchange Offers in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act, and the rules and regulations of the SEC. Outstanding Bonds that are not tendered for exchange in the Exchange Offers will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits such holders have under the Indenture relating to such holders' series of Outstanding Bonds except we will not have any further obligation to you to provide for the registration of the Outstanding Bonds under the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered Outstanding Bonds when we have given written notice of the acceptance to the exchange agent. The exchange agent will act as agent for the tendering holders for the purposes of receiving the Exchange Bonds from us and delivering Exchange Bonds to holders. Subject to the terms of the registration rights agreement, we expressly reserve the right to amend or terminate the Exchange Offers and to refuse to accept Exchange Bonds upon the occurrence of any of the conditions specified below under "—Conditions to the Exchange Offers."

If you tender your Outstanding Bonds in the Exchange Offers, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of Outstanding Bonds. We will pay all charges and expenses, other than certain applicable taxes described below in connection with the Exchange Offers. It is important that you read "—Fees and Expenses" below for more details regarding fees and expenses incurred in the Exchange Offers.

If you are a broker-dealer and receive Exchange Bonds for your own account in exchange for Outstanding Bonds that you acquired as a result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the Exchange Bonds and that you did not purchase your Outstanding Bonds from us or any of our affiliates. Read "Plan of Distribution" for more details regarding the transfer of Exchange Bonds.

We make no recommendation to you as to whether you should tender or refrain from tendering all or any portion of your Outstanding Bonds into these Exchange Offers. In addition, no one has been authorized to make this recommendation. You must make your own decision whether to tender into these Exchange Offers and, if so, the aggregate amount of Outstanding Bonds to tender after reading this prospectus and the letter of transmittal and consulting with your advisors, if any, based on your financial position and requirements.

The Exchange Offers expire at 5:00 p.m., New York City time, on June 30, 2011, which we refer to as the "Expiration Date." However, if we, in our sole discretion, extend the period of time for which the Exchange Offers are open, the term "Expiration Date" will mean the latest date to which we shall have extended the expiration of the Exchange Offers.

To extend the period of time during which the Exchange Offers are open, we will notify the exchange agent of any extension by written notice, followed by notification by press release or other public announcement to the registered holders of the Outstanding Bonds no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date. During

any extension, all Outstanding Bonds previously tendered will remain subject to this Exchange Offer unless validly withdrawn.

Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice to the registered holders of the Outstanding Bonds. If we amend any of the Exchange Offers in a manner that we determine to constitute a material change, we will promptly disclose the amendment in a manner reasonably calculated to inform the holders of applicable Outstanding Bonds of that amendment, and we will extend such Exchange Offer to the extent required by law.

In the event we terminate the Exchange Offers, all Outstanding Bonds previously tendered and not accepted for payment will be returned promptly to the tendering holders.

Despite any other term of the Exchange Offers, we will not be required to accept for exchange, or to issue Exchange Bonds in exchange for, any Outstanding Bonds and we may terminate or amend any of the Exchange Offers as provided in this prospectus prior to the Expiration Date if in our reasonable judgment:

In addition, we will not be obligated to accept for exchange the Outstanding Bonds of any holder that has not made to us:

We expressly reserve the right at any time or at various times to extend the period of time during which the Exchange Offers are open. Consequently, we may delay acceptance of any Outstanding Bonds by giving oral or written notice of such extension to the holders. We will return any Outstanding Bonds that we do not accept for exchange for any reason without expense to the tendering holder promptly after the expiration or termination of the Exchange Offers. We also expressly reserve the right to amend or terminate any of the Exchange Offers and to reject for exchange any Outstanding Bonds not previously accepted for exchange, if we determine that any of the conditions of the Exchange Offers specified above have not been satisfied. We will give oral or written notice of any extension,

amendment, non-acceptance or termination to the holders of the Outstanding Bonds as promptly as practicable. In the case of any extension, such notice will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

We reserve the right to waive any defects, irregularities or conditions to the exchange as to particular Outstanding Bonds. These conditions are for our sole benefit, and we may assert them regardless of the circumstances that may give rise to them or waive them in whole or in part at any or at various times prior to the expiration of the Exchange Offers in our sole discretion. If we fail at any time to exercise any of the foregoing rights, this failure will not constitute a waiver of such right. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the Exchange Offers.

In addition, we will not accept for exchange any Outstanding Bonds tendered, and will not issue Exchange Bonds in exchange for any such Outstanding Bonds, if at such time any stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the Indenture under the Trust Indenture Act of 1939, as amended.

To tender your Outstanding Bonds in the Exchange Offers, you must comply with either of the following:

The term "Agent's Message" means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, which states that:

Your tender, if not withdrawn prior to the expiration of the Exchange Offers, constitutes an agreement between us and you upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

The method of delivery of Outstanding Bonds, letters of transmittal and all other required documents to the exchange agent is at your election and risk. Delivery of such documents will be deemed made only when actually received by the exchange agent. We recommend that instead of delivery by mail, you use an overnight or hand delivery service, properly insured. If you determine to make delivery by mail, we suggest that you use properly insured, registered mail with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery to the exchange agent before the expiration of the Exchange Offers. Letters of transmittal and certificates representing Outstanding Bonds should be sent only to the exchange agent, and not to us or to any book-entry transfer facility. No alternative, conditional or contingent tenders of Outstanding Bonds will be accepted. You may request that your broker, dealer, commercial bank, trust company or nominee effect the above transactions for you.

If you are a beneficial owner whose Outstanding Bonds are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your Outstanding Bonds, you should promptly contact the registered holder and instruct the registered holder to tender on your behalf. If you wish to tender the Outstanding Bonds yourself, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Bonds, either:

The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration of the Exchange Offers.

Signatures on the letter of transmittal or a notice of withdrawal (as described below in "—Withdrawal Rights"), as the case may be, must be guaranteed by a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the US or another "eligible guarantor institution" within the meaning of Rule 17A(d)-15 under the Exchange Act unless the Outstanding Bonds surrendered for exchange are tendered:

If the letter of transmittal is signed by a person other than the registered holder of any Outstanding Bonds listed on the Outstanding Bonds, such Outstanding Bonds must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder's name appears on the Outstanding Bonds, and an eligible guarantor institution must guarantee the signature on the bond power.

If the letter of transmittal, any certificates representing Outstanding Bonds or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should also indicate when signing and, unless waived by us, they should also submit evidence satisfactory to us of their authority to so act.

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC's system may use DTC's Automated Tender Offer Program to tender Outstanding Bonds. Participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent, electronically transmit their acceptance of Outstanding Bonds for exchange by causing DTC to transfer the Outstanding Bonds to the exchange agent in accordance with DTC's Automated Tender Offer Program procedures for transfer. DTC will then send an Agent's Message to the exchange agent.

Promptly after the date of this prospectus, the exchange agent will establish an account with respect to the Outstanding Bonds at DTC, as the book-entry transfer facility, for purposes of the Exchange Offers. Any financial institution that is a participant in the book-entry transfer facility's system may make book-entry delivery of the Outstanding Bonds by causing the book-entry transfer facility to transfer those Outstanding Bonds into the exchange agent's account at the facility in accordance with the facility's procedures for such transfer. To be timely, book-entry delivery of Outstanding Bonds requires receipt of a confirmation of a book-entry transfer, or a "book-entry confirmation," prior to the Expiration Date.

In addition, in order to receive Exchange Bonds for tendered Outstanding Bonds, an Agent's Message in connection with a book-entry transfer into the exchange agent's account at the book-entry transfer facility or the letter of transmittal or a manually signed facsimile thereof, together with any required signature guarantees and any other required documents must be delivered or transmitted to and received by the exchange agent at its address set forth on the cover page of the letter of transmittal prior to the expiration of the Exchange Offers. Holders of Outstanding Bonds who are unable to deliver confirmation of the book-entry tender of their Outstanding Bonds into the exchange agent's account at the book-entry transfer facility or an Agent's Message or a letter of transmittal or a manually signed facsimile thereof in lieu thereof and all other documents required by the letter of transmittal to the exchange agent prior to the expiration of the Exchange Offers must tender their Outstanding Bonds according to the guaranteed delivery procedures described below. Tender will not be deemed made until such documents are received by the exchange agent. Delivery of documents to the book-entry transfer facility does not constitute delivery to the exchange agent.

If you wish to tender your Outstanding Bonds but your Outstanding Bonds are not immediately available or you cannot deliver your Outstanding Bonds, the letter of transmittal or any other required documents to the exchange agent or comply with the procedures under DTC's Automatic Tender Offer Program in the case of Outstanding Bonds, prior to the Expiration Date, you may still tender if:

Upon request, the exchange agent will send to you a notice of guaranteed delivery if you wish to tender your Outstanding Bonds according to the guaranteed delivery procedures.

In all cases, we will promptly issue Exchange Bonds of the applicable series for Outstanding Bonds that we have accepted for exchange under the Exchange Offers only after the exchange agent timely receives:

In addition, each broker-dealer that is to receive Exchange Bonds for its own account in exchange for Outstanding Bonds must represent that such Outstanding Bonds were acquired by that broker-dealer as a result of market-making activities or other trading activities and must acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the Exchange Bonds. The letters of transmittal state that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. See "Plan of Distribution."

We will interpret the terms and conditions of the Exchange Offers, including the letters of transmittal and the instructions to the letters of transmittal, and will resolve all questions as to the validity, form, eligibility, including time of receipt, and acceptance of Outstanding Bonds tendered for exchange. Our determinations in this regard will be final and binding on all parties. We reserve the absolute right to reject any and all tenders of any particular Outstanding Bonds not properly tendered or to not accept any particular Outstanding Bonds if the acceptance might, in our or our counsel's judgment, be unlawful. We also reserve the absolute right to waive any defects or irregularities as to any particular Outstanding Bonds prior to the expiration of the Exchange Offers.

Unless waived, any defects or irregularities in connection with tenders of Outstanding Bonds for exchange must be cured within such reasonable period of time as we determine. Neither the Company, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity with respect to any tender of Outstanding Bonds for exchange, nor will any of them incur any liability for any failure to give notification. Any certificates representing Outstanding Bonds received by the exchange agent that are not properly tendered and as to which the irregularities have not been cured or waived will be returned by the exchange agent to the tendering holder, unless otherwise provided in the letter of transmittal, promptly after the expiration or termination of the Exchange Offers.

Except as otherwise provided in this prospectus, you may withdraw your tender of Outstanding Bonds at any time prior to 5:00 p.m., New York City time, on the Expiration Date.

If certificates for Outstanding Bonds have been delivered or otherwise identified to the exchange agent, then, prior to the release of such certificates, you must also submit:

If Outstanding Bonds have been tendered pursuant to the procedures for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn Outstanding Bonds and otherwise comply with the procedures of the facility. We will determine all questions as to the validity, form and eligibility, including time of receipt of notices of withdrawal, and our determination will be final and binding on all parties. Any Outstanding Bonds so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the Exchange Offers. Any Outstanding Bonds that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder, without cost to the holder, or, in the case of book-entry transfer, the Outstanding Bonds will be credited to an account at the book-entry transfer facility, promptly after withdrawal, rejection of tender or termination of the Exchange Offers. Properly withdrawn Outstanding Bonds may be retendered by following the procedures described under "—Procedures for Tendering Outstanding Bonds" above at any time prior to the expiration of the Exchange Offers.

The Bank of New York Mellon has been appointed as the exchange agent for the Exchange Offers. The Bank of New York Mellon also acts as trustee under the Indenture. You should direct all executed letters of transmittal and all questions and requests for assistance with respect to accepting or withdrawing from the Exchange Offers, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery to the exchange agent addressed as follows:

If you deliver the letter of transmittal to an address other than the one set forth above or transmit instructions via facsimile to a number other than the one set forth above, that delivery or those instructions will not be effective.

The registration rights agreement provides that we will bear all expenses in connection with the performance of our obligations relating to the registration of the Exchange Bonds and the conduct of the Exchange Offers. These expenses include registration and filing fees, accounting and legal fees and printing costs, among others. We will pay the exchange agent reasonable and customary fees for its services and reasonable out-of-pocket expenses. We will also reimburse brokerage houses and other custodians, nominees and fiduciaries for customary mailing and handling expenses incurred by them in

forwarding this prospectus and related documents to their clients that are holders of Outstanding Bonds and for handling or tendering for such clients.

We have not retained any dealer-manager in connection with the Exchange Offers and will not pay any fee or commission to any broker, dealer, nominee or other person for soliciting tenders of Outstanding Bonds pursuant to the Exchange Offers.

We will record the Exchange Bonds in our accounting records at the same carrying value as the Outstanding Bonds, which is the aggregate principal amount as reflected in our accounting records on the date of exchanges. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of the Exchange Offers. We will record the costs of the Exchange Offers as incurred.

We will pay all transfer taxes, if any, applicable to the exchanges of Outstanding Bonds under the Exchange Offers. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

If satisfactory evidence of payment of such taxes is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed to that tendering holder.

Holders who tender their Outstanding Bonds for exchange will not be required to pay any transfer taxes. However, holders who instruct us to register Exchange Bonds in the name of, or request that Outstanding Bonds not tendered or not accepted in the Exchange Offers be returned to, a person other than the registered tendering holder will be required to pay any applicable transfer tax.

If you do not exchange your Outstanding Bonds for Exchange Bonds under the Exchange Offers, your Outstanding Bonds will remain subject to the restrictions on transfer of such Outstanding Bonds:

In general, you may not offer or sell your Outstanding Bonds unless they are registered under the Securities Act or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the Outstanding Bonds under the Securities Act.

Participating in the Exchange Offers is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered Outstanding Bonds in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any Outstanding Bonds that are not tendered in the Exchange Offers or to file a registration statement to permit resales of any untendered Outstanding Bonds.

The following summary description sets forth certain terms and provisions of the Exchange Bonds. Because this description is a summary, it does not describe every aspect of the Exchange Bonds or the Mortgage (as defined below) under which the Exchange Bonds will be issued, and which is filed as an exhibit to the registration statement of which this prospectus is a part. The Mortgage and its associated documents contain the full legal text of the matters described in this section. This summary is subject to and qualified in its entirety by reference to all of the provisions of the Exchange Bonds and the Mortgage, including definitions of certain terms used in the Mortgage. We also include references in parentheses to certain sections of the Mortgage. Whenever we refer to particular sections or defined terms of the Mortgage in this prospectus, such sections or defined terms are incorporated by reference herein.

The form and terms of the Exchange Bonds are identical in all material respects to the form and terms of the Outstanding Bonds except the Exchange Bonds will:

We will issue each series of the Exchange Bonds under our indenture, dated as of October 1, 2010 (as such indenture may be amended and supplemented from time to time, the Mortgage), to The Bank of New York Mellon, as Trustee. The Mortgage effectively does not limit the aggregate principal amount of bonds or other debt securities that may be issued thereunder, subject to meeting certain conditions to issuance, including those described below under "Issuance of Additional Mortgage Securities." The Exchange Bonds and all other debt securities issued previously or hereafter issued under the Mortgage are collectively referred to herein as "Mortgage Securities." The Mortgage constitutes a first mortgage lien, subject to Permitted Liens and exceptions and exclusions as described below, on substantially all of our real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage and distribution of natural gas. (See "—Security; Lien of the Mortgage" below.) As of the date of this prospectus, in addition to the Outstanding Bonds, approximately $574 million of first mortgage bonds are issued and outstanding under the Mortgage, and have been pledged to secure pollution control revenue bonds issued by two counties in Kentucky on our behalf.

The Exchange Bonds will be issued in fully registered form only, without coupons. The Exchange Bonds will be initially represented by one or more fully registered global securities deposited with the Trustee, as custodian for DTC, as depositary, and registered in the name of DTC or DTC's nominee. A beneficial interest in a Global Security will be shown on, and transfers or exchanges thereof will be effected only through, records maintained by DTC and its participants, as described below under "—Book-Entry Only Issuance—The Depository Trust Company." The authorized denominations of the Exchange Bonds will be $2,000 and any larger amount that is an integral multiple of $1,000. Except in limited circumstances described below, the Exchange Bonds will not be exchangeable for Bonds in definitive certificated form.

The 2015 Exchange Bonds will be issued as part of the same series of debt securities under the Indenture as the 2015 Outstanding Bonds. The 2040 Exchange Bonds will be issued as part of the same

series of debt securities under the Indenture as the 2040 Outstanding Bonds. We may, without the consent of the holders of the applicable series of Bonds, increase the principal amount of any series of Bonds and issue additional bonds of the applicable series having the same ranking, interest rate, maturity and other terms (other than the date of issuance and, in some circumstances, the initial interest accrual date and initial interest payment date) as the Exchange Bonds, but do not intend to reopen a series unless, for U.S. federal income tax purposes, such additional bonds are issued in a "qualified reopening" within the meaning of the Internal Revenue Code of 1986, as amended. Any such additional bonds would, together with the Exchange Bonds of the applicable series offered by this prospectus and any Outstanding Bonds of the related series, constitute a single series of securities under the Mortgage and may be treated as a single class for all purposes under the Mortgage, including, without limitation, voting waivers and amendments.

The 2015 Exchange Bonds will mature on November 15, 2015 and will bear interest from May 15, 2011 (the last Interest Payment Date on which interest was paid on the Outstanding Bonds of the same series), at a rate of 1.625% per annum. The 2040 Bonds will mature on November 15, 2040 and will bear interest from May 15, 2011 (the last Interest Payment Date on which interest was paid on the Outstanding Bonds of the same series), at a rate of 5.125% per annum. Interest will be payable on each series of Bonds on May 15 and November 15 of each year, commencing on November 15, 2011, and at maturity (whether at the applicable stated maturity date, upon redemption or acceleration, or otherwise). Subject to certain exceptions, the Mortgage provides for the payment of interest on an Interest Payment Date only to persons in whose names the Exchange Bonds are registered at the close of business on the Regular Record Date, which will be the May 1 and November 1 (whether or not a Business Day), as the case may be, immediately preceding the applicable Interest Payment Date; except that interest payable at Maturity will be paid to the person to whom principal is paid.

Interest on the Exchange Bonds will be calculated on the basis of a 360-day year of twelve 30-day months, and with respect to any period less than a full calendar month, on the basis of the actual number of days elapsed during the period.

If we default in paying interest on an Exchange Bond, we will pay such defaulted interest either

We will pay principal of and interest and premium, if any, on the Exchange Bonds at Maturity upon presentation of the Exchange Bonds at the corporate trust office of The Bank of New York Mellon in New York, New York, as our Paying Agent. In our discretion, we may change the place of payment on the Exchange Bonds, and we may remove any Paying Agent and may appoint one or more additional Paying Agents (including us or any of our affiliates). (See Section 702.)

If any Interest Payment Date, Redemption Date or Maturity of an Exchange Bond falls on a day that is not a Business Day, the required payment of principal, premium, if any, and/or interest will be made on the next succeeding Business Day as if made on the date such payment was due, and no interest will accrue on such payment for the period from and after such Interest Payment Date,

Redemption Date or Maturity, as the case may be, to the date of such payment on the next succeeding Business Day.

"Business Day" means any day, other than a Saturday or Sunday, that is not a day on which banking institutions or trust companies in The City of New York, New York, or other city in which a paying agent for such Bond is located, are generally authorized or required by law, regulation or executive order to remain closed. (See Section 116.)

So long as the Exchange Bonds are registered in the name of DTC, as depository for the Exchange Bonds as described herein under "—Book-Entry Only Issuance—The Depository Trust Company" or DTC's nominee, transfers and exchanges of beneficial interest in the Exchange Bonds will be made as described therein. In the event that the book-entry only system is discontinued, and the Exchange Bonds are issued in certificated form, you may exchange or transfer Exchange Bonds at the corporate trust office of the Trustee.

You may have your Exchange Bonds divided into Exchange Bonds of smaller denominations (of at least $2,000 and any larger amount that is an integral multiple of $1,000) or combined into Exchange Bonds of larger denominations, as long as the total principal amount is not changed. (See Section 305.)

There will be no service charge for any transfer or exchange of the Exchange Bonds, but you may be required to pay a sum sufficient to cover any tax or other governmental charge payable in connection therewith. We may block the transfer or exchange of (1) Exchange Bonds during a period of 15 days prior to giving any notice of redemption or (2) any Exchange Bond selected for redemption in whole or in part, except the unredeemed portion of any Exchange Bond being redeemed in part. (See Section 305.)

The Trustee acts as our agent for registering Exchange Bonds in the names of holders and transferring the Exchange Bonds. We may appoint another agent (including one of our affiliates) or act as our own agent for this purpose. The entity performing the role of maintaining the list of registered holders is called the "Security Registrar." It will also perform transfers. In our discretion, we may change the place for registration of transfer of the Exchange Bonds and may designate a different entity as the Security Registrar, including us or one of our affiliates. (See Sections 305 and 702.)

We may, at our option, redeem the 2015 Exchange Bonds, in whole at any time or in part from time to time, at a redemption price equal to the greater of (1) 100% of the principal amount of the 2015 Exchange Bonds to be so redeemed; or (2) as determined by the Quotation Agent, the sum of the present values of the remaining scheduled payments of principal and interest on the 2015 Exchange Bonds to be so redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the Redemption Date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Adjusted Treasury Rate, plus 10 basis points; plus, in either case, accrued and unpaid interest on the principal amount of the 2015 Exchange Bonds to be so redeemed to the Redemption Date.

We may, at our option, redeem the 2040 Exchange Bonds, in whole at any time or in part from time to time. If the 2040 Exchange Bonds are redeemed before May 15, 2040 (the date that is six months prior to the stated maturity of the 2040 Exchange Bonds), the 2040 Exchange Bonds will be redeemed by us at a redemption price equal to the greater of (1) 100% of the principal amount of the 2040 Exchange Bonds to be so redeemed; or (2) as determined by the Quotation Agent, the sum of the present values of the remaining scheduled payments of principal and interest on the 2040 Exchange Bonds to be so redeemed (not including any portion of such payments of interest accrued to the date

of redemption) discounted to the Redemption Date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Adjusted Treasury Rate, plus 20 basis points; plus, in either case, accrued and unpaid interest on the principal amount of the 2040 Exchange Bonds to be so redeemed to the Redemption Date. If the 2040 Exchange Bonds are redeemed on or after May 15, 2040, the 2040 Exchange Bonds will be redeemed by us at a redemption price equal to 100% of the principal amount of the 2040 Exchange Bonds to be so redeemed, plus accrued and unpaid interest on the principal amount of the 2040 Exchange Bonds to be so redeemed to the Redemption Date.

"Adjusted Treasury Rate" means, with respect to any Redemption Date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for that Redemption Date.

"Comparable Treasury Issue" means the United States Treasury security selected by the Quotation Agent as having an actual or interpolated maturity comparable to the remaining term of the applicable series of Exchange Bonds to be redeemed to the applicable stated maturity date that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such applicable series of Exchange Bonds being redeemed.

"Quotation Agent" means one of the Reference Treasury Dealers appointed by us.

"Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Quotation Agent, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount), as provided to the Quotation Agent by that Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding that Redemption Date.

The Exchange Bonds will not be subject to a sinking fund or other mandatory redemption provisions and will not be repayable at the option of the holder prior to the applicable stated maturity date.

The Exchange Bonds will be redeemable upon notice of redemption to each holder of Exchange Bonds to be redeemed by mail between 30 days and 60 days prior to the Redemption Date. If less than all of the Exchange Bonds are to be redeemed, the Trustee will select the Exchange Bonds or portions thereof to be redeemed. In the absence of any provision for selection, the Trustee will choose a method of random selection that it deems fair and appropriate. (See Sections 503 and 504.)

We may make any redemption at our option conditional upon the receipt by the Paying Agent, on or prior to the date fixed for redemption, of money sufficient to pay the redemption price. If the

Paying Agent has not received such money by the date fixed for redemption, we will not be required to redeem such Exchange Bonds. (See Section 504.)

If money sufficient to pay the redemption price has been received by the Paying Agent, Exchange Bonds called for redemption will cease to bear interest on the Redemption Date. We will pay the redemption price and any accrued interest once you surrender the Exchange Bond for redemption. (See Section 505.) If only part of an Exchange Bond is redeemed, the Trustee will deliver to you a new Exchange Bond of the same series for the remaining portion without charge. (See Section 506.)

We may redeem, in whole or in part, one series of Exchange Bonds without redeeming the other series.

Except as described below under this heading and under "—Issuance of Additional Mortgage Securities," and subject to the exceptions described under "—Satisfaction and Discharge," all Mortgage Securities, including the Exchange Bonds, will be secured, equally and ratably, by the lien of the Mortgage, which constitutes, subject to Permitted Liens as described below, a first mortgage lien on substantially all of our real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage, transportation and distribution of natural gas (other than property duly released from the lien of the Mortgage in accordance with the provisions thereof and other than Excepted Property, as described below). We sometimes refer to our property that is subject to the lien of the Mortgage as "Mortgaged Property."

We may obtain the release of property from the lien of the Mortgage from time to time, upon the bases provided for such release in the Mortgage. See "—Release of Property."

We may enter into supplemental indentures with the Trustee, without the consent of the holders, in order to subject additional property (including property that would otherwise be excepted from such lien) to the lien of the Mortgage. (See Section 1401.) This property would constitute Property Additions and would be available as a basis for the issuance of Mortgage Securities. See "—Issuance of Additional Mortgage Securities."

The Mortgage provides that after-acquired property (other than Excepted Property) will be subject to the lien of the Mortgage. (See Granting Clause Second.) However, in the case of consolidation or merger (whether or not we are the surviving company) or transfer of the Mortgaged Property as or substantially as an entirety, the Mortgage will not be required to be a lien upon any of the properties either owned or subsequently acquired by the successor company except properties acquired from us in or as a result of such transfer, as well as improvements, extensions and additions (as defined in the Mortgage) to such properties and renewals, replacements and substitutions of or for any part or parts thereof. See Section 1303 and "—Consolidation, Merger and Conveyance of Assets as an Entirety."

Excepted Property. The lien of the Mortgage does not cover, among other things, the following types of property: property located outside of Kentucky and not specifically subjected or required to be subjected to the lien of the Mortgage; property not used by us in our electric generation, transmission and distribution business or our gas storage, transportation and distribution facilities; cash and securities not paid, deposited or held under the Mortgage or required so to be; contracts, leases and other agreements of all kinds, contract rights, bills, notes and other instruments, revenues, accounts receivable, claims, demands and judgments; governmental and other licenses, permits, franchises, consents and allowances; intellectual property rights and other general intangibles; vehicles, movable equipment, aircraft and vessels; all goods, stock in trade, wares, merchandise and inventory held for the purpose of sale or lease in the ordinary course of business; materials, supplies, inventory and other

personal property consumable in the operation of our business; fuel; tools and equipment; furniture and furnishings; computers and data processing, telecommunications and other facilities used primarily for administrative or clerical purposes or otherwise not used in connection with the operation or maintenance of electric generation, transmission and distribution facilities or natural gas storage, transportation and distribution facilities; coal, ore, gas, oil and other minerals and timber rights; electric energy and capacity, gas, steam, water and other products generated, produced, manufactured, purchased or otherwise acquired; real property and facilities used primarily for the production or gathering of natural gas; property which has been released from the lien of the Mortgage; and leasehold interests. We sometimes refer to our property not covered by the lien of the Mortgage as "Excepted Property." (See Granting Clauses.) Properties held by any of our subsidiaries, as well as properties leased from others, would not be subject to the lien of the Mortgage.

Permitted Liens. The lien of the Mortgage is subject to Permitted Liens described in the Mortgage. Such Permitted Liens include liens existing at the execution date of the Mortgage, purchase money liens and other liens placed or otherwise existing on property acquired by us after the execution date of the Mortgage at the time we acquire it, tax liens and other governmental charges which are not delinquent or which are being contested in good faith, mechanics', construction and materialmen's liens, certain judgment liens, easements, reservations and rights of others (including governmental entities) in, and defects of title to, our property, certain leases and leasehold interests, liens to secure public obligations, rights of others to take minerals, timber, electric energy or capacity, gas, water, steam or other products produced by us or by others on our property, rights and interests of Persons other than us arising out of agreements relating to the common ownership or joint use of property, and liens on the interests of such Persons in such property and liens which have been bonded or for which other security arrangements have been made. (See Granting Clauses and Section 101.)

The Mortgage also provides that the Trustee will have a lien, prior to the lien on behalf of the holders of the Mortgage Securities, upon the Mortgaged Property as security for our payment of its reasonable compensation and expenses and for indemnity against certain liabilities. (See Section 1107.) Any such lien would be a Permitted Lien under the Mortgage.

The maximum principal amount of Mortgage Securities that may be authenticated and delivered under the Mortgage is subject to the issuance restrictions described below; provided, however, that the maximum principal amount of Mortgage Securities outstanding at any one time shall not exceed One Quintillion Dollars ($1,000,000,000,000,000,000), which amount may be changed by supplemental indenture. (See Section 301.) Mortgage Securities of any series may be issued from time to time on the basis of, and in an aggregate principal amount not exceeding:

Property Additions generally include any property which is owned by us and is subject to the lien of the Mortgage except (with certain exceptions) goodwill, going concern value rights or intangible property, or any property the acquisition or construction of which is properly chargeable to one of our

operating expense accounts in accordance with U.S. generally accepted accounting principles. (See Section 104.)

Retired Securities means, generally, Mortgage Securities which are no longer outstanding under the Mortgage, which have not been retired by the application of Funded Cash and which have not been used as the basis for the authentication and delivery of Mortgage Securities, the release of property or the withdrawal of cash.

We issued the Outstanding Bonds on the basis of property additions. The Exchange Bonds will be issued in exchange for Outstanding Bonds, with no additional property being required. At February 28, 2011, approximately $875 million of Property Additions were available to us to be used as the basis for the authentication and delivery of Mortgage Securities in addition to the Outstanding Bonds (or the Exchange Bonds). (See Article Four.)

Unless an Event of Default has occurred and is continuing, we may obtain the release from the lien of the Mortgage of any Mortgaged Property, except for cash held by the Trustee, upon delivery to the Trustee of an amount in cash equal to the amount, if any, by which sixty-six and two-thirds percent (66²/3%) of the Cost of the property to be released (or, if less, the Fair Value to us of such property at the time it became Funded Property) exceeds the aggregate of:

As used in the Mortgage, the term "Purchase Money Lien" means, generally, a lien on the property being released which is retained by the transferor of such property or granted to one or more other persons in connection with the transfer or release thereof, or granted to or held by a trustee or agent for any such persons, and may include liens which cover property in addition to the property being released and/or which secure indebtedness in addition to indebtedness to the transferor of such property. (See Section 101.)

Unless an Event of Default has occurred and is continuing, property which is not Funded Property may generally be released from the lien of the Mortgage without depositing any cash or property with the Trustee as long as (a) the aggregate amount of Cost or Fair Value to us (whichever is less) of all

Property Additions which do not constitute Funded Property (excluding the property to be released) after certain deductions and additions, primarily including adjustments to offset property retirements, is not less than zero or (b) the Cost or Fair Value (whichever is less) of property to be released does not exceed the aggregate amount of the Cost or Fair Value to us (whichever is less) of Property Additions acquired or made within the 90-day period preceding the release. (See Section 804.)

The Mortgage provides simplified procedures for the release of minor properties and property taken by eminent domain, and provides for dispositions of certain obsolete property and grants or surrender of certain rights without any release or consent by the Trustee. (See Sections 805, 807 and 808.)

If we retain any interest in any property released from the lien of the Mortgage, the Mortgage will not become a lien on such property or such interest therein or any improvements, extensions or additions to such property or renewals, replacements or substitutions of or for such property or any part or parts thereof. (See Section 809.)

Unless an Event of Default has occurred and is continuing, and subject to certain limitations, cash held by the Trustee may, generally, (1) be withdrawn by us (a) to the extent of sixty-six and two-thirds percent (66²/3%) of the Cost or Fair Value to us (whichever is less) of Property Additions not constituting Funded Property, after certain deductions and additions, primarily including adjustments to offset retirements (except that such adjustments need not be made if such Property Additions were acquired or made within the 90-day period preceding the withdrawal) or (b) in an amount equal to the aggregate principal amount of Mortgage Securities that we would be entitled to issue on the basis of Retired Securities (with the entitlement to such issuance being waived by operation of such withdrawal) or (c) in an amount equal to the aggregate principal amount of any outstanding Mortgage Securities delivered to the Trustee; or (2) upon our request, be applied to (a) the purchase of Mortgage Securities in a manner and at a price approved by us or (b) the payment (or provision for payment) at stated maturity of any Mortgage Securities or the redemption (or provision for payment) of any Mortgage Securities which are redeemable (see Section 806); provided, however, that cash deposited with the Trustee as the basis for the authentication and delivery of Mortgage Securities may, in addition, be withdrawn in an amount not exceeding the aggregate principal amount of cash delivered to the Trustee for such purpose. (See Section 404.)

If an Event of Default occurs and is continuing, then either the Trustee or the holders of not less than 25% in principal amount of the outstanding Mortgage Securities may declare the principal amount of all of the Mortgage Securities to be due and payable immediately. (See Section 1002.)

After the declaration of acceleration has been made and before the Trustee has obtained a judgment or decree for payment of the money due, such declaration and its consequences will be rescinded and annulled, if

For more information as to waiver of defaults, see "—Waiver of Default and of Compliance" below.

Subject to the Mortgage, under certain circumstances and to the extent permitted by law, if an Event of Default occurs and is continuing, the Trustee has the power to appoint a receiver of the Mortgaged Property, and is entitled to all other remedies available to mortgagees and secured parties under the Uniform Commercial Code or any other applicable law. (See Section 1016.)

Subject to the Mortgage, if an Event of Default occurs and is continuing, the holders of a majority in principal amount of the outstanding Mortgage Securities will have the right to

The rights of holders to make direction are subject to the following limitations:

The Trustee may also take any other action it deems proper which is not inconsistent with the holders' direction. (See Sections 1012 and 1103.)

In addition, the Mortgage provides that no holder of any Mortgage Security will have any right to institute any proceeding, judicial or otherwise, with respect to the Mortgage for the appointment of a receiver or for any other remedy thereunder unless

Furthermore, no holder will be entitled to institute any such action if and to the extent that such action would disturb or prejudice the rights of other holders. (See Sections 1007 and 1103.)

However, each holder has an absolute and unconditional right to receive payment when due and to bring a suit to enforce that right. (See Section 1008.)

The Trustee is required to give the holders of the Mortgage Securities notice of any default under the Mortgage to the extent required by the Trust Indenture Act, unless such default has been cured or waived; except that in the case of an Event of Default of the character specified in the third bullet point under "—Events of Default" (regarding a breach of certain covenants continuing for 90 days after the receipt of a written notice of default), no such notice shall be given to such holders until at least 60 days after the occurrence thereof. (See Section 1102.) The Trust Indenture Act currently permits the Trustee to withhold notices of default (except for certain payment defaults) if the Trustee in good faith determines the withholding of such notice to be in the interests of the holders.

We will furnish the Trustee with an annual statement as to our compliance with the conditions and covenants in the Mortgage. (See Section 709.)

The holders of a majority in aggregate principal amount of the outstanding Mortgage Securities may waive, on behalf of the holders of all outstanding Mortgage Securities, any past default under the Mortgage, except a default in the payment of principal, premium or interest, or with respect to compliance with certain provisions of the Mortgage that cannot be amended without the consent of the holder of each outstanding Mortgage Security affected. (See Section 1013.)

Compliance with certain covenants in the Mortgage or otherwise provided with respect to Mortgage Securities may be waived by the holders of a majority in aggregate principal amount of the affected Mortgage Securities, considered as one class. (See Section 710.)

Subject to the provisions described below, we have agreed to preserve our corporate existence. (See Section 704.)

We have agreed not to consolidate with or merge with or into any other entity or convey, transfer or lease the Mortgaged Property as or substantially as an entirety to any entity unless

In the case of the conveyance or other transfer of the Mortgaged Property as or substantially as an entirety to any other person, upon the satisfaction of all the conditions described above we would be released and discharged from all obligations under the Mortgage and on the Mortgage Securities then outstanding unless we elect to waive such release and discharge. (See Section 1304.)

If following a conveyance or other transfer, or lease, of any part of the Mortgaged Property, the fair value of the Mortgaged Property retained by the Company exceeds an amount equal to three-halves (³/2) of the aggregate principal amount of all outstanding Mortgage Securities, then the part of the Mortgaged Property so conveyed, transferred or leased shall be deemed not to constitute the entirety or substantially the entirety of the Mortgaged Property. This fair value will be determined within 90 days of the conveyance or transfer by an independent expert that we select and that is approved by the Trustee.

So long as any Exchange Bonds are outstanding under the Mortgage, during such periods as we are not subject to the periodic reporting requirements of Section 13 or 15(d) of the Exchange Act, we

shall make available to holders of the Exchange Bonds by means of posting on our website or other similar means:

If we are unable, for any reason, to post the financial statements on our website as described above, we shall furnish the financial statements to the Trustee, who has agreed, at our expense, to furnish them to the holders of the Exchange Bonds.

Without Holder Consent. Without the consent of any holders of Mortgage Securities, we and the Trustee may enter into one or more supplemental indentures for any of the following purposes:

In addition, if the Trust Indenture Act is amended after the date of the Mortgage so as to require changes to the Mortgage or so as to permit changes to, or the elimination of, provisions which, at the date of the Mortgage or at any time thereafter, were required by the Trust Indenture Act to be contained in the Mortgage, the Mortgage will be deemed to have been amended so as to conform to such amendment or to effect such changes or elimination, and we and the Trustee may, without the consent of any holders, enter into one or more supplemental indentures to effect or evidence such amendment.

With Holder Consent. Except as provided above, the consent of the holders of at least a majority in aggregate principal amount of the Mortgage Securities of all outstanding series, considered as one class, is generally required for the purpose of adding to, or changing or eliminating any of the provisions of, the Mortgage pursuant to a supplemental indenture. However, if less than all of the series of outstanding Mortgage Securities are directly affected by a proposed supplemental indenture, then such proposal only requires the consent of the holders of a majority in aggregate principal amount of the outstanding Mortgage Securities of all directly affected series, considered as one class. Moreover, if the Mortgage Securities of any series have been issued in more than one tranche and if the proposed supplemental indenture directly affects the rights of the holders of Mortgage Securities of one or more, but less than all, of such tranches, then such proposal only requires the consent of the holders of a majority in aggregate principal amount of the outstanding Mortgage Securities of all directly affected tranches, considered as one class.

However, no amendment or modification may, without the consent of the holder of each outstanding Mortgage Security directly affected thereby,

A supplemental indenture which changes, modifies or eliminates any provision of the Mortgage expressly included solely for the benefit of holders of Mortgage Securities of one or more particular series or tranches will be deemed not to affect the rights under the Mortgage of the holders of Mortgage Securities of any other series or tranche.

Any Mortgage Securities or any portion thereof will be deemed to have been paid and no longer outstanding for purposes of the Mortgage and, at our election, our entire indebtedness with respect to those securities will be satisfied and discharged, if there shall have been irrevocably deposited with the Trustee or any Paying Agent (other than the Company), in trust:

to pay when due the principal of, and any premium, and interest due and to become due on such Mortgage Securities or portions of such Mortgage Securities on and prior to their maturity.

Our right to cause our entire indebtedness in respect of the Mortgage Securities of any series to be deemed to be satisfied and discharged as described above will be subject to the satisfaction of any conditions specified in the instrument creating such series.

The Mortgage will be deemed satisfied and discharged when no Mortgage Securities remain outstanding and when we have paid all other sums payable by us under the Mortgage. (See Section 902.)

All moneys we pay to the Trustee or any Paying Agent on Exchange Bonds that remain unclaimed at the end of two years after payments have become due may be paid to or upon our order. Thereafter, the holder of such Exchange Bond may look only to us for payment. (See Section 703.)

Duties of the Trustee; Resignation and Removal of the Trustee; Deemed Resignation

The Trustee will have, and will be subject to, all the duties and responsibilities specified with respect to an indenture trustee under the Trust Indenture Act. Subject to these provisions, the Trustee will be under no obligation to exercise any of the powers vested in it by the Mortgage at the request of any holder of Mortgage Securities, unless offered reasonable indemnity by such holder against the costs, expenses and liabilities which might be incurred thereby. The Trustee will not be required to expend or risk its own funds or otherwise incur financial liability in the performance of its duties if the Trustee reasonably believes that repayment or adequate indemnity is not reasonably assured to it.

The Trustee may also be removed by act of the holders of a majority in principal amount of the then outstanding Mortgage Securities of any series.

No resignation or removal of the Trustee and no appointment of a successor trustee will become effective until the acceptance of appointment by a successor trustee in accordance with the requirements of the Mortgage.

Under certain circumstances, we may appoint a successor trustee and if the successor accepts, the Trustee will be deemed to have resigned.

Notices to holders of the Exchange Bonds will be given by mail to the addresses of the holders as they may appear in the Security Register. (See Section 109.)

The Company, the Trustee, and any agent of the Company or the Trustee, will treat the person or entity in whose name the Exchange Bonds are registered as the absolute owner of those Exchange Bonds (whether or not such Exchange Bonds may be overdue) for the purpose of making payments and for all other purposes irrespective of notice to the contrary. (See Section 308.)

Compliance with Mortgage provisions is evidenced by written statements of our officers or persons selected or paid by us. In certain cases, opinions of counsel and certifications of an engineer, accountant, appraiser or other expert (who in some cases must be independent) must be furnished. In addition, the Mortgage requires us to give to the Trustee, not less than annually, a brief statement as to our compliance with the conditions and covenants under the Mortgage.

The Mortgage provides that certain Mortgage Securities, including those for which payment or redemption money has been deposited or set aside in trust as described under "—Satisfaction and Discharge" above, will not be deemed to be "outstanding" in determining whether the holders of the requisite principal amount of the outstanding Mortgage Securities have given or taken any demand, direction, consent or other action under the Mortgage as of any date, or are present at a meeting of holders for quorum purposes. (See Section 101.)

We will be entitled to set any day as a record date for the purpose of determining the holders of outstanding Mortgage Securities of any series entitled to give or take any demand, direction, consent or other action under the Mortgage, in the manner and subject to the limitations provided in the Mortgage. In certain circumstances, the Trustee also will be entitled to set a record date for action by holders. If such a record date is set for any action to be taken by holders of particular Mortgage Securities, such action may be taken only by persons who are holders of such Mortgage Securities on the record date. (See Section 107.)

The Mortgage and the Mortgage Securities provide that they are to be governed by and construed in accordance with the laws of the State of New York except where the Trust Indenture Act is applicable or where otherwise required by law. (See Section 115.) The effectiveness of the lien of the Mortgage, and the perfection and priority thereof, will be governed by Kentucky law.

The Trustee under the Mortgage is the Bank of New York Mellon. In addition to acting as Trustee, BNYM also maintains various banking and trust relationships with us and some of our affiliates.

DTC will act as the initial securities depository for the Exchange Bonds. The Exchange Bonds issued in exchange for Outstanding Bonds will be issued as fully-registered securities registered in the name of Cede & Co. (DTC's partnership nominee) or such other name as may be requested by an authorized representative of DTC. One fully-registered certificate will be issued with respect to each $500 million of principal amount of Exchange Bonds, and an additional certificate will be issued with respect to any remaining principal amount of Exchange Bonds. The global bonds will be deposited with the Trustee as custodian for DTC.

DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds securities for its participants, or Direct Participants, and also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants' accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation, or DTCC. DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly. The rules that apply to DTC and those using its system are on file with the SEC. More information about DTC can be found at www.dtcc.com.

Purchases of the Exchange Bonds under the DTC system must be made by or through Direct Participants, which will receive a credit for the Exchange Bonds on DTC's records. The ownership interest of each actual purchaser, or beneficial owner, is in turn to be recorded on the Direct and Indirect Participants' records. Beneficial owners will not receive written confirmation from DTC of their purchases, but beneficial owners should receive written confirmations providing details of the transactions, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which they entered into the transaction. Transfers of ownership interests on the Exchange Bonds are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in Exchange Bonds, except in the event that use of the book-entry system for the Exchange Bonds is discontinued.

To facilitate subsequent transfers, all Exchange Bonds deposited by Direct Participants with DTC are registered in the name of DTC's partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of the Exchange Bonds with DTC and their registration in the name of Cede & Co. or such other nominee do not effect any change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the Exchange Bonds; DTC's records reflect only the identity of the Direct Participants to whose accounts the Exchange Bonds are credited, which may or may not be the beneficial owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to beneficial owners, will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Notices will be sent to DTC.

Neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to the Exchange Bonds unless authorized by a Direct Participant in accordance with DTC's procedures. Under its usual procedures, DTC mails an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns the voting or consenting rights of Cede & Co. to those Direct Participants to whose accounts the Exchange Bonds are credited on the record date. We believe that these arrangements will enable the beneficial owners to exercise rights equivalent in substance to the rights that can be directly exercised by a registered holder of the Exchange Bonds.

Payments of principal and interest on the Exchange Bonds will be made to Cede & Co. (or such other nominee of DTC). DTC's practice is to credit Direct Participants' accounts upon DTC's receipt of funds and corresponding detail information from us or the Trustee, on payable date in accordance with their respective holdings shown on DTC's records. Payments by participants to beneficial owners will be governed by standing instructions and customary practices and will be the responsibility of such participant and not of DTC, the Trustee or us, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of the principal and interest to Cede & Co. (or such other nominee of DTC) is the responsibility of the Company or the Trustee. Disbursement of such payments to Direct Participants will be the responsibility of DTC, and disbursement of such payments to the beneficial owners is the responsibility of Direct and Indirect Participants.

A beneficial owner will not be entitled to receive physical delivery of the Exchange Bonds. Accordingly, each beneficial owner must rely on the procedures of DTC to exercise any rights under the Exchange Bonds.

DTC may discontinue providing its services as securities depository with respect to the Exchange Bonds at any time by giving us or the Trustee reasonable notice. In the event no successor securities depository is obtained, certificates for the Exchange Bonds will be printed and delivered.

The information in this section concerning DTC and DTC's book-entry system has been obtained from sources that we believe to be reliable; however, we do not take any responsibility for the accuracy of this information.

The following discussion summarizes material U.S. federal income tax considerations to U.S. Holders and Non-U.S. Holders (each, as defined below) of the acquisition, ownership and disposition of the Exchange Bonds acquired pursuant to the Exchange Offers. It is included herein for general information purposes only. The discussion set forth below is limited to holders who hold the Exchange Bonds as capital assets within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended, and does not address all tax considerations that may be relevant to investors in light of their personal investment circumstances or that may be relevant to certain types of investors subject to special rules (for example, financial institutions, tax-exempt organizations, insurance companies, regulated investment companies, persons that are broker-dealers, traders in securities who elect the mark to market method of tax accounting for their securities, U.S. Holders that have a functional currency other than the U.S. dollar, certain former U.S. citizens or long-term residents, retirement plans, real estate investment trusts, foreign governments, international organizations, controlled foreign corporations, passive foreign investment companies, investors in partnerships or other pass-through entities or persons holding the Exchange Bonds as part of a "straddle," "hedge," "conversion transaction" or other integrated transaction).

In addition, this discussion does not address the effect of U.S. federal alternative minimum tax, gift or estate tax laws, or any state, local or foreign tax laws. Furthermore, the discussion below is based upon provisions of the Internal Revenue Code, the legislative history thereof, U.S. Treasury regulations thereunder and administrative rulings and judicial decisions thereunder as of the date hereof. Such authorities may be repealed, revoked or modified (including changes in effective dates, and possibly with retroactive effect) so as to result in U.S. federal income tax considerations different from those discussed below. We have not sought any rulings from the Internal Revenue Service with respect to the statements and conclusions made in the following discussion, and there can be no assurance that the IRS will agree with such statements and conclusions or that a court will not sustain any challenge by the IRS in the event of litigation.

For purposes of the following discussion, the term "U.S. Holder" means a beneficial owner of the Exchange Bonds that is for U.S. federal income tax purposes:

For purposes of the following discussion, the term "Non-U.S. Holder" means a beneficial owner of the Exchange Bonds (other than a partnership or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder for U.S. federal income tax purposes.

If an entity or arrangement treated as a partnership for U.S. federal income tax purposes is a beneficial owner of a Bond, the U.S. federal income tax treatment of a partner in the partnership generally will depend upon the status of the partner and upon the activities of the partnership. Partnerships and partners in such partnerships should consult their own tax advisors about the tax consequences of the ownership and disposition of the Exchange Bonds.

THIS DISCUSSION OF MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS IS NOT INTENDED, AND SHOULD NOT BE CONSTRUED, TO BE TAX OR LEGAL ADVICE TO ANY PARTICULAR INVESTOR IN OR HOLDER OF THE EXCHANGE BONDS. HOLDERS ARE ADVISED TO CONSULT THEIR OWN TAX ADVISORS CONCERNING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSIDERATIONS ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING JURISDICTION OR ANY APPLICABLE TAX TREATIES, AND THE POSSIBLE EFFECT OF CHANGES IN APPLICABLE TAX LAW.

The exchange of Outstanding Bonds for Exchange Bonds pursuant to the Exchange Offers will not constitute a taxable event for U.S. federal income tax purposes. As a result:

In certain circumstances (for example, see "Description of the Exchange Bonds—Redemption") we may be obligated to pay amounts on the Exchange Bonds that are in excess of stated interest or principal on the Exchange Bonds. These potential payments may implicate the provisions of the treasury regulations relating to "contingent payment debt instruments." One or more contingencies will not cause the Exchange Bonds to be treated as a contingent payment debt instrument if, as of the issue date, each such contingency is considered remote or incidental or, in certain circumstances, it is significantly more likely than not that none of the contingencies will occur. We believe that the potential for additional payments on the Exchange Bonds should not cause the Exchange Bonds to be treated as contingent payment debt instruments under the treasury regulations relating to contingent payment debt instruments. Our determination is binding on a holder unless such a holder discloses its contrary position in the manner required by applicable Treasury Regulations. However, the IRS may take a different position, which could require a holder to accrue income on its Exchange Bonds in excess of stated interest, and to treat any income realized on the taxable disposition of an Exchange Bond as ordinary income rather than capital gain. The remainder of this discussion assumes that the Exchange Bonds will not be treated as contingent payment debt instruments. Holders should consult their own tax advisors regarding the possible application of the contingent payment debt instrument rules to the Exchange Bonds.

The Exchange Bonds will be issued without any original issue discount for U.S. federal income tax purposes. Accordingly, stated interest on the Exchange Bonds will be included in income by a U.S. Holder as ordinary income as such interest is received or accrued in accordance with the U.S. Holder's method of accounting for U.S. federal income tax purposes.

Upon a sale, taxable exchange, redemption (including any optional redemption) or other taxable disposition of an Exchange Bond, a U.S. Holder generally will recognize gain or loss equal to the difference between the amount realized on the disposition, other than amounts attributable to accrued but unpaid interest not yet taken into income which will be taxed as ordinary income, and the U.S. Holder's adjusted tax basis in the Exchange Bond. A U.S. Holder's adjusted tax basis in an Exchange Bond generally will equal the purchase price of the Outstanding Bond exchanged for the Exchange Bond. Any gain or loss generally will constitute capital gain or loss and will be long-term capital gain or loss if the U.S. Holder has held the Exchange Bond for longer than 12 months. Long-term capital gain, in the case of non-corporate taxpayers, is eligible for preferential rates of taxation. Under current law, the deductibility of capital losses is subject to limitations.

For taxable years beginning after December 31, 2012, a U.S. Holder that is an individual or estate, or a trust that does not fall into a special class of trusts that is exempt from such tax, will be subject to a 3.8% tax on the lesser of (1) the U.S. Holder's "net investment income" (in the case of individuals) or "undistributed net investment income" (in the case of estates and trusts) for the relevant taxable year and (2) the excess of the U.S. Holder's "modified adjusted gross income" (in the case of individuals) or "adjusted gross income" (in the case of estates and trusts) for the taxable year over a certain threshold (which in the case of individuals will be between $125,000 and $250,000, depending on the individual's circumstances). A U.S. Holder's net investment income generally will include its interest income on the Exchange Bonds and its net gains from the disposition of the Exchange Bonds, unless such interest income or net gains are derived in the ordinary course of the conduct of a trade or business (other than a trade or business that consists of certain passive or trading activities). U.S. Holders that are individuals, estates or trusts should consult their own tax advisors regarding the applicability of the Medicare tax to their income and gains in respect of the Exchange Bonds.

Under the Internal Revenue Code, U.S. Holders may be subject, under certain circumstances, to information reporting and "backup withholding" with respect to cash payments in respect of principal, interest and the gross proceeds from dispositions of the Exchange Bonds, unless the U.S. Holder is an exempt recipient. Backup withholding applies only if the U.S. Holder fails to furnish its social security or other taxpayer identification number to the Paying Agent and to comply with certain certification procedures or otherwise fails to establish an exemption from backup withholding. Backup withholding is not an additional tax. Any amount withheld from a payment to a U.S. Holder under the backup withholding rules is allowable as a credit (and may entitle such holder to a refund) against such U.S. Holder's U.S. federal income tax liability, provided that the required information is furnished to the IRS in a timely manner. Certain persons are exempt from backup withholding. U.S. Holders should consult their own tax advisors as to their qualification for exemption from backup withholding and the procedure for obtaining such exemption.

Subject to the discussion of backup withholding below, payments of interest on the Exchange Bonds to a Non-U.S. Holder generally will not be subject to U.S. withholding tax provided that (1) the Non-U.S. Holder does not actually or constructively own 10% or more of the total combined voting power of all classes of our voting stock, (2) the Non-U.S. Holder is not (a) a controlled foreign corporation that is related to us through actual or deemed stock ownership or (b) a bank receiving

interest on an extension of credit made pursuant to a loan agreement entered into in the ordinary course of business, (3) such interest is not effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States, and (4) either (a) the Non-U.S. Holder provides its name and address on an IRS Form W-8BEN (or other applicable form) and certifies, under penalties of perjury, that it is not a United States person as defined under the Internal Revenue Code or (b) a securities clearing organization, bank or other financial institution holding the Exchange Bonds on the Non-U.S. Holder's behalf certifies, under penalties of perjury, that it has received a properly executed IRS Form W-8BEN from the Non-U.S. Holder and it provides the withholding agent with a copy.

If a Non-U.S. Holder cannot satisfy the requirements in the preceding paragraph, payments of interest made to such Non-U.S. Holder will be subject to U.S. federal withholding tax, currently at a rate of 30%, unless such Non-U.S. Holder (1) timely provides the withholding agent with a properly executed IRS Form W-8BEN (or other applicable form) claiming an exemption from or reduction in withholding under the benefit of an applicable income tax treaty or IRS Form W-8ECI (or other applicable form) certifying that interest paid on the Exchange Bonds is not subject to U.S. federal withholding tax because it is effectively connected with such Non-U.S. Holder's conduct of a trade or business in the United States, or (2) otherwise properly establishes an exemption from withholding taxes.

If interest on the Exchange Bonds is effectively connected with the conduct by a Non-U.S. Holder of a trade or business within the United States (and, if certain tax treaties apply, is attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder), such interest will be subject to U.S. federal income tax on a net income basis at the rate applicable to United States persons generally (and a Non-U.S. Holder that is treated as a corporation for U.S. federal income tax purposes may also be subject to a branch profits tax equal to 30% of its effectively connected earnings and profits, subject to certain adjustments, unless such holder qualifies for a lower rate under an applicable income tax treaty). If interest is subject to U.S. federal income tax on a net income basis in accordance with these rules, such payments will not be subject to U.S. federal withholding tax so long as the relevant Non-U.S. Holder timely provides the withholding agent with the appropriate documentation.

Subject to the discussion of backup withholding below, any gain realized by a Non-U.S. Holder on the sale, taxable exchange, redemption or other taxable disposition of the Exchange Bonds generally will not be subject to U.S. federal income tax, unless (1) such gain is effectively connected with the conduct by such Non-U.S. Holder of a trade or business within the United States (and, if certain tax treaties apply, is attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder), in which case such gain will be taxed on a net income basis in the same manner as interest that is effectively connected with the Non-U.S. Holder's conduct of a trade or business within the United States (and a Non-U.S. Holder that is treated as a corporation for U.S. federal income tax purposes may also be subject to the branch profits tax as described above) or (2) the Non-U.S. Holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other conditions are satisfied, in which case the Non-U.S. Holder will be subject to a tax, currently at a rate of 30%, on the excess, if any, of such gain plus all other U.S source capital gains recognized during the same taxable year over the Non-U.S. Holder's U.S. source capital losses recognized during such taxable year.

A Non-U.S. Holder may be subject to annual information reporting and U.S. federal backup withholding on payments of interest and proceeds of a sale or other disposition of the Exchange Bonds unless such Non-U.S. Holder provides the certification described above under "Non-U.S. Holders—

Stated Interest" or otherwise establishes an exemption from backup withholding. Backup withholding is not an additional tax and will be refunded or allowed as a credit against the Non-U.S. Holder's U.S. federal income tax liability (if any), provided the required information is furnished to the IRS in a timely manner. In any event, we generally will be required to file information returns with the IRS reporting our payments on the Exchange Bonds. Copies of the information returns may also be made available to the tax authorities in the country in which a Non-U.S. Holder resides under the provisions of an applicable income tax treaty.

Non-U.S. Holders should consult their own tax advisors regarding the application of the information reporting and backup withholding rules in their particular situations, the availability of an exemption therefrom and the procedure for obtaining such an exemption, if available.

Recently enacted legislation regarding foreign account tax compliance, effective for payments made after December 31, 2012, imposes a withholding tax of 30% on interest and gross proceeds from the disposition of certain debt instruments paid to certain foreign entities unless various information reporting and certain other requirements are satisfied. However, the withholding tax will not be imposed on payments pursuant to obligations outstanding as of March 18, 2012. In addition, certain account information with respect to U.S. Holders who hold the Exchange Bonds through certain foreign financial institutions may be reportable to the IRS. Investors should consult with their own tax advisors regarding the possible implications of this recently enacted legislation to them.

THE PRECEDING DISCUSSION IS FOR GENERAL INFORMATION PURPOSES ONLY AND IS NOT TAX ADVICE. ACCORDINGLY, EACH HOLDER OF AN EXCHANGE BOND SHOULD CONSULT ITS OWN TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES TO IT OF ACQUIRING, OWNING AND DISPOSING OF THE EXCHANGE BONDS ACQUIRED PURSUANT TO THE TERMS OF THE EXCHANGE OFFERS, INCLUDING THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS, AND OF ANY PROPOSED CHANGES IN APPLICABLE LAW.

Each broker-dealer that receives Exchange Bonds for its own account pursuant to the Exchange Offers must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Bonds. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Bonds received in exchange for Outstanding Bonds where such Outstanding Bonds were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the Expiration Date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, all dealers effecting transactions in the Exchange Bonds may be required to deliver a prospectus.

We will not receive any proceeds from any sale of Exchange Bonds by broker-dealers. Exchange Bonds received by broker-dealers for their own account pursuant to the Exchange Offers may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Bonds or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such Exchange Bonds. Any broker-dealer that resells Exchange Bonds that were received by it for its own account pursuant to the Exchange Offers and any broker or dealer that participates in a distribution of such Exchange Bonds may be deemed to be an "underwriter" within the meaning of the Securities Act, and any profit on any such resale of Exchange Bonds and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 180 days after the Expiration Date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. Subject to certain limitations set forth in the registration rights agreement, we have agreed to pay all expenses incident to the Exchange Offers (including the expenses of one counsel for the holders of the Outstanding Bonds) other than commissions or concessions of any brokers or dealers and will indemnify you (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

The validity of the Exchange Bonds has been passed upon for us by Dewey & LeBoeuf LLP, New York, New York, John R. McCall, Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer to the Company and Stoll Keenon Ogden PLLC. As to matters involving the law of the Commonwealth of Kentucky, Dewey & LeBoeuf will rely upon the opinion of Mr. McCall and Stoll Keenon Ogden PLLC.

Our financial statements as of December 31, 2010 and 2009 and for the periods from January 1, 2010 to October 31, 2010, and November 1, 2010 to December 31, 2010, and for each of the two years in the period ended December 31, 2009 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, independent registered public accounting firm, given the authority of said firm as experts in auditing and accounting.

We have filed with the SEC a registration statement on Form S-4 under the Securities Act with respect to the Exchange Bonds. This prospectus, which forms a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information with respect to us and the Exchange Bonds, reference is made to the registration statement. Statements contained in this prospectus as to the contents of any contract or other document are not complete.

We have agreed to make certain information available to holders of the Bonds, as described under "Description of the Exchange Bonds—Agreement to Provide Information."

The Company is not currently subject to the informational requirements of the Exchange Act. As a result of the offering of the Exchange Bonds, we will become subject to the informational requirements of the Exchange Act and, in accordance therewith, will file reports and other information with the SEC. These reports and other information can be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also read and copy these SEC filings by visiting the SEC's website at http://www.sec.gov.

You may request additional copies of our reports or copies of our other SEC filings at no cost by writing or telephoning us at the following address:

Louisville Gas and Electric Company
220 West Main Street
Louisville, Kentucky 40202
Attention: Corporate Secretary
Telephone: (502) 627-2000

Louisville Gas and Electric Company

INDEX TO FINANCIAL STATEMENTS

Audited Financial Statements as of December 31, 2010 and 2009,
and for the Years Ended December 31, 2010, 2009 and 2008

Unaudited Condensed Financial Statements as of March 31, 2011 and December 31, 2010,
and for the Three Months Ended March 31, 2011 and 2010

As of December 31, 2010 and 2009,
and for the Years Ended December 31, 2010, 2009 and 2008


AG		Attorney General of Kentucky
ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
BART		Best Available Retrofit Technology
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CATR		Clean Air Transport Rule
CCN		Certificate of Public Convenience and Necessity
Clean Air Act		The Clean Air Act, as amended in 1990
CMRG		Carbon Management Research Group
Company		Louisville Gas and Electric Company
CT		Combustion Turbine
DSM		Demand Side Management
ECR		Environmental Cost Recovery
EKPC		East Kentucky Power Cooperative, Inc.
E.ON		E.ON AG
E.ON U.S.		E.ON U.S. LLC and Subsidiaries
EPA		U.S. Environmental Protection Agency
EPAct 2005		Energy Policy Act of 2005
FAC		Fuel Adjustment Clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		Flue Gas Desulfurization
Fidelia		Fidelia Corporation (an E.ON affiliate)
GAAP		U.S. Generally Accepted Accounting Principles
GHG		Greenhouse Gas
GSC		Gas Supply Clause
Gwh		Gigawatt hours or one thousand Mwh
IBEW		International Brotherhood of Electrical Workers
IMEA		Illinois Municipal Electric Agency
IMPA		Indiana Municipal Power Agency
IRS		Internal Revenue Service
KCCS		Kentucky Consortium for Carbon Storage
KDAQ		Kentucky Division for Air Quality
Kentucky Commission		Kentucky Public Service Commission
KIUC		Kentucky Industrial Utility Consumers, Inc.
KU		Kentucky Utilities Company
kWh		Kilowatt hours
LG&E		Louisville Gas and Electric Company
LIBOR		London Interbank Offered Rate
LKE		LG&E and KU Energy LLC and Subsidiaries (formerly E.ON U.S. LLC and Subsidiaries)
Mcf		Thousand Cubic Feet
MMcf		Million Cubic Feet
MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		Million British thermal units
Moody's		Moody's Investor Services, Inc.
MVA		Megavolt-ampere
Mw		Megawatts


Mwh		Megawatt hours
NAAQS		National Ambient Air Quality Standards
NERC		North American Electric Reliability Corporation
NO₂		Nitrogen Dioxide
NOx		Nitrogen Oxide
OATT		Open Access Transmission Tariff
OVEC		Ohio Valley Electric Corporation
PBR		Performance Based Rates
PPL		PPL Corporation
Predecessor		The Company during the time period prior to November 1, 2010
PUHCA 2005		Public Utility Holding Company Act of 2005
RSG		Revenue Sufficiency Guarantee
S&P		Standard & Poor's Rating Service
SCR		Selective Catalytic Reduction
SERC		SERC Reliability Corporation
Servco		LG&E and KU Services Company (formerly E.ON U.S. Services Inc.)
SIP		State Implementation Plan
SO₂		Sulfur Dioxide
SPP		Southwest Power Pool, Inc.
Successor		The Company during the time period after October 31, 2010
TC1		Trimble County Unit 1
TC2		Trimble County Unit 2
TVA		Tennessee Valley Authority
Utilities		LG&E and KU
VDT		Value Delivery Team Process
Virginia Commission		Virginia State Corporation Commission
WNA		Weather Normalization Adjustment

In our opinion, the accompanying balance sheet and the related statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the financial position of Louisville Gas and Electric Company (Predecessor Company) at December 31, 2009 and the results of its operations and its cash flows for the period from January 1, 2010 to October 31, 2010 and for each of the two years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.

In our opinion, the accompanying balance sheet and the related statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the financial position of Louisville Gas and Electric Company (Successor Company) at December 31, 2010 and the results of its operations and its cash flows for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.



			Successor			Predecessor
									Year Ended December 31,
			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			Year Ended December 31,
			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			2009		2008
Operating revenues (Note 15):			$	254		$	1,057		$	1,272	$	1,468
Operating expenses:
	Fuel for electric generation			60			306			328		346
	Power purchased (Notes 13 and 15)			10			45			59		120
	Natural gas supply expenses			53			109			243		347
	Other operation and maintenance expenses			68			294			339		309
	Depreciation and amortization (Note 1)			23			115			136		127

		Total operating expenses		214			869			1,105		1,249

		Operating income		40			188			167		219
Derivative gain (loss) (Note 5)				—			19			18		(37	)
Interest expense (Notes 5, 11 and 12)				7			16			17		29
Interest expense to affiliated companies (Notes 11, 12 and 15)				1			22			27		29
Other income (expense)—net				(3	)		(2	)		1		7

		Income before income taxes		29			167			142		131
Income tax expense (Note 10)				10			58			47		41

		Net income	$	19		$	109		$	95	$	90



				Successor			Predecessor
				December 31, 2010			December 31, 2009
Assets
Current assets:
	Cash and cash equivalents			$	2		$	5
	Accounts receivable (less allowance for doubtful accounts: 2010, $2; 2009, $2):
		Customer			70			66
		Affiliated companies			30			53
		Other			13			12
	Unbilled revenues				81			65
	Available for sale debt securities				163			—
	Fuel, materials and supplies:
		Fuel (predominantly coal)			68			61
		Natural gas stored underground			60			56
		Other materials and supplies			34			33
	Other intangible assets				36			—
	Regulatory assets (Note 3)				13			14
	Prepayments and other current assets				13			18

Total current assets					583			383

Property, plant and equipment:
	Regulated utility plant—electric and natural gas				2,600			4,200
	Accumulated depreciation				(17	)		(1,708	)

			Net regulated utility plant		2,583			2,492
	Construction work in progress				385			342

			Property, plant and equipment—net		2,968			2,834

Deferred debits and other assets:
	Regulatory assets (Notes 3 and 9)
		Pension and postretirement benefits			213			204
		Other regulatory assets			154			125
	Goodwill (Notes 2 and 7)				389			—
	Other intangible assets (Notes 2 and 7)				181			—
	Other assets				31			22

Total deferred debits and other assets					968			351

Total assets				$	4,519		$	3,568



			Successor		Predecessor
			December 31, 2010		December 31, 2009
Liabilities and Equity
Current liabilities:
	Current portion of long-term debt (Note 11)		$	—	$	120
	Notes payable to affiliated companies (Notes 12 and 15)			12		170
	Note payable			163		—
	Accounts payable			100		97
	Accounts payable to affiliated companies (Note 15)			20		28
	Accrued taxes			10		27
	Customer deposits			23		22
	Regulatory liabilities (Note 3)			51		38
	Accrued interest			5		3
	Employee accruals			17		12
	Other current liabilities			16		16

Total current liabilities				417		533

Long-term debt:
	Long-term bonds (Note 11)			1,112		291
	Long-term debt to affiliated company (Note 11 and 15)			—		485

Total long-term debt				1,112		776

Deferred credits and other liabilities:
	Deferred income taxes (Note 10)			419		373
	Accumulated provision for pensions (Note 9)			126		198
	Investment tax credits (Note 10)			46		48
	Asset retirement obligations (Notes 3 and 4)			49		31
	Regulatory liabilities (Note 3):
		Accumulated cost of removal of utility plant		275		259
		Other regulatory liabilities		208		44
	Derivative liabilities (Note 5)			32		28
	Other liabilities			114		25

Total deferred credits and other liabilities				1,269		1,006

Equity:
	Common stock, without par value—authorized 75,000,000 shares, outstanding 21,294,223 shares			424		424
	Additional paid-in capital			1,278		84
	Retained earnings:
		Retained earnings		19		755
		Accumulated other comprehensive loss (Note 17)		—		(10	)

Total equity				1,721		1,253

Total liabilities and equity			$	4,519	$	3,568



			Successor			Predecessor
									Year Ended December 31,
			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			Year Ended December 31,
			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			2009			2008
Cash flows from operating activities:
	Net income		$	19		$	109		$	95		$	90
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization		23			115			136			127
		Deferred income taxes—net		13			23			17			(5	)
		Investment tax credits (Note 10)		—			(2	)		(2	)		4
		Provision for pension and postretirement benefits		6			20			33			13
		Unrealized (gain) loss on derivatives		—			14			(33	)		48
		Regulatory asset for unrealized gain on interest rate swaps (Note 3)		—			(22	)		—			—
		Other—net		2			2			(3	)		(7	)
	Change in current assets and liabilities:
		Accounts receivable		(29	)		(2	)		38			(3	)
		Unbilled revenues		(38	)		22			18			(11	)
		Fuel, materials and supplies		10			(22	)		45			(37	)
		Regulatory assets		2			(9	)		—			—
		Natural gas supply clause receivable, net		—			—			29			13
		Other current assets		5			(6	)		(1	)		1
		Accounts payable		16			—			37			(145	)
		Accounts payable to affiliated companies		(31	)		23			(52	)		144
		Accrued taxes		(2	)		(15	)		8			18
		Regulatory liabilities		1			(24	)		—			—
		Other current liabilities		(5	)		7			(1	)		(5	)
	Pension and postretirement benefits funding (Note 9)			(1	)		(25	)		(15	)		(7	)
	Storm restoration regulatory asset (Note 3)			—			—			(44	)		(24	)
	Other regulatory assets			1			—			—			—
	Change in collateral deposit—interest rate swap			—			—			5			(10	)
	Other regulatory liabilities			—			(11	)		—			—
	Change in other comprehensive income			—			—			6			(8	)
	Other—net			—			(8	)		(7	)		1

Net cash provided by (used in) operating activities				(8	)		189			309			197



			Successor			Predecessor
									Year Ended December 31,
			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			Year Ended December 31,
			November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			2009			2008
Cash flows from investing activities:
	Construction expenditures		$	(65	)	$	(155	)	$	(186	)	$	(243	)
	Proceeds from sale of assets to affiliated company			—			48			—			10
	Proceeds from sale of assets			—			—			3			9
	Change in restricted cash			2			—			—			—
	Cash settlement on derivatives			—			—			7			(8	)

Net cash provided by (used in) investing activities				(63	)		(107	)		(176	)		(232	)

Cash flows from financing activities:
	Issuance of bonds (Note 11)			531			—			—			—
	Issuance of short-term note payable (Note 12)			163			—			—			—
	Short-term borrowings from affiliated company—net (Note 12)			(130	)		(28	)		(52	)		144
	Other borrowings from affiliated companies (Note 11)			485			—			—			75
	Repayments on other borrowings to affiliated companies (Note 11)			(485	)		—			—			—
	Repayments to E.ON affiliate (Note 11)			(485	)		—			—			—
	Debt issuance costs			(10	)		—			—			—
	Acquisition of outstanding bonds			—			—			—			(259	)
	Reissuance of reacquired bonds			—			—			—			95
	Payment of dividends			—			(55	)		(80	)		(40	)
	Capital contribution (Note 15)			—			—			—			20

Net cash provided by (used in) financing activities				69			(83	)		(132	)		35

Change in cash and cash equivalents				(2	)		(1	)		1			—
Cash and cash equivalents at beginning of period				4			5			4			4

Cash and cash equivalents at end of period			$	2		$	4		$	5		$	4

Supplemental disclosures of cash flow information:
	Cash paid (received) during the year for:
		Interest—net of amount capitalized	$	11		$	39		$	36		$	38
		Income taxes—net		(8	)		60			23			24



				Successor		Predecessor
				December 31, 2010		December 31, 2009
Long-term debt (Note 11):
	Pollution control series:
		Jefferson Co. 2001 Series A, due September 1, 2026, variable %		$	22	$	22
		Trimble Co. 2001 Series A, due September 1, 2026, variable %			28		28
		Jefferson Co. 2000 Series A, due May 1, 2027, 5.375%			25		25
		Jefferson Co. 2001 Series A, due September 1, 2027, variable %			10		10
		Jefferson Co. 2001 Series B, due November 1, 2027, variable %			35		35
		Trimble Co. 2001 Series B, due November 1, 2027, variable %			35		35
		Trimble Co. 2000 Series A, due August 1, 2030, variable %			83		83
		Trimble Co. 2002 Series A, due October 1, 2032, variable %			42		42
		Trimble Co. 2007 Series A, due June 1, 2033, 4.60%			60		60
		Louisville Metro 2007 Series A, due June 1, 2033, 5.625%			31		31
		Louisville Metro 2007 Series B, due June 1, 2033, variable %			35		35
		Louisville Metro 2003 Series A, due October 1, 2033, variable %			128		128
		Louisville Metro 2005 Series A, due February 1, 2035, 5.75%			40		40

Total pollution control series					574		574

First mortgage bonds:
		First mortgage bond 2015 Series, due November 15, 2015, 1.625%			250		—
		First mortgage bond 2040 Series, due November 15, 2040, 5.125%			285		—

Total first mortgage bonds					535		—

Notes payable to Fidelia:
		Due January 16, 2012, 4.33%, unsecured			—		25
		Due April 30, 2013, 4.55%, unsecured			—		100
		Due August 15, 2013, 5.31%, unsecured			—		100
		Due November 23, 2015, 6.48%, unsecured			—		50
		Due July 25, 2018, 6.21%, unsecured			—		25
		Due November 26, 2022, 5.72%, unsecured			—		47
		Due April 13, 2031, 5.93%, unsecured			—		68
		Due April 13, 2037, 5.98%, unsecured			—		70

Total notes payable to Fidelia					—		485

Total long-term debt outstanding					1,109		1,059

Total long-term debt outstanding				$	1,109	$	1,059
		Less reacquired debt			—		163
		Purchase-accounting adjustments and discounts (net)			3		—
		Less current portion of long-term debt			—		120

Long-term debt					1,112		776

Common equity:
	Common stock, without par value—
			Authorized 75,000,000 shares, outstanding 21,294,223 shares		424		424
			Additional paid-in capital		1,278		84
	Accumulated other comprehensive loss (Note 17)				—		(10	)
	Retained earnings				19		755

Total common equity					1,721		1,253

Total capitalization				$	2,833	$	2,029

Terms and abbreviations are explained in the index of abbreviations. Dollars are in millions unless otherwise noted.

LG&E, incorporated in Kentucky in 1913, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy and the storage, distribution and sale of natural gas. LG&E provides electric service to approximately 395,000 customers in Louisville and adjacent areas in Kentucky covering approximately 700 square miles in nine counties. Natural gas service is provided to approximately 320,000 customers in its electric service area and eight additional counties in Kentucky. Approximately 95% of the electricity generated by LG&E is produced by its coal-fired electric generating stations, all equipped with systems to reduce SO2 emissions. The remainder is generated by natural gas and oil fueled CTs and a hydroelectric power plant. Underground natural gas storage fields help the Company provide economical and reliable natural gas service to customers.

On November 1, 2010, LG&E became an indirect wholly owned subsidiary of PPL, when PPL acquired all of the outstanding limited liability company interests in the Company's direct parent, LKE, from E.ON US Investments Corp. LKE, a Kentucky limited liability company, also owns the affiliate, KU, a regulated utility engaged in the generation, transmission, distribution and sale of electric energy in Kentucky, Virginia and Tennessee. Following the acquisition, the Company's business has not changed. LG&E and KU are continuing as subsidiaries of LKE, which is now an intermediary holding company in the PPL group of companies.

Headquartered in Allentown, Pennsylvania, PPL is an energy and utility holding company that was incorporated in 1994. Through its subsidiaries, PPL owns or controls about 19,000 megawatts of generating capacity in the U.S., sells energy in key U.S. markets and delivers electricity and natural gas to about 5.3 million customers in the U.S. and the U.K.

LG&E's basis of accounting incorporates the business combinations guidance of the FASB ASC as of the date of the acquisition, which requires the recognition and measurement of identifiable assets acquired and liabilities assumed at fair value as of the acquisition date. LG&E's financial statements and accompanying footnotes have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Predecessor covers the time period prior to November 1, 2010. Successor covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL accounting policies, which are discussed below, and the cost basis of certain assets and liabilities were changed as of November 1, 2010, as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Predecessor period are not comparable to the Successor period.

Despite the separate presentation, the core operations of the Company have not changed. See Note 2, Acquisition by PPL, for information regarding the acquisition and the purchase accounting adjustments.

Certain reclassification entries have been made to the Predecessor's previous years' financial statements to conform to the 2010 presentation with no impact on total assets, liabilities and capitalization or previously reported net income and cash flows. These reclassifications mainly consist of those necessary to identify amounts for prior periods that are separately disclosed in the financial statements.

LG&E is a cost-based rate-regulated utility. As a result, the financial statements reflect the effects of regulatory actions. Regulatory assets are recognized for the effect of transactions or events where future recovery is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise be charged to expense. Likewise, regulatory liabilities may be recognized for obligations expected to be returned through future regulated customer rates. The effect of such transactions or events would otherwise be reflected as income, or, in certain cases, regulatory liabilities are recorded based on the understanding with the regulator that current rates are being set to recover costs that are expected to be incurred in the future. The regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. Offsetting regulatory assets or liabilities for fair value purchase accounting adjustments have also been recorded to eliminate any ratemaking impact of the fair value adjustments. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC or the Kentucky Commission. See Note 3, Rates and Regulatory Matters, for additional detail regarding regulatory assets and liabilities.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

LG&E enters into interest rate swap contracts to hedge exposure to variability in expected cash flows associated with existing debt instruments. LG&E enters into energy trading contracts to manage price risk and to maximize the value of power sales from the physical assets it owns.

Interest rate swap contracts and energy trading contracts meet the definition of a derivative and are reflected on the Balance Sheets at fair value in accordance with the derivatives and hedging guidance of the FASB ASC. Beginning in the third quarter of 2010, the change in fair value of interest rate swap contracts is recorded as regulatory assets or liabilities based on an Order from the Kentucky Commission in the 2010 rate case whereby the cost of a terminated swap was allowed to be recovered in base rates. Prior to the third quarter, interest rate swaps designated as effective cash flow hedges had resulting gains and losses recorded within other comprehensive income and common equity. The ineffective portion of interest rate swaps designated as cash flow hedges was previously recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps. The energy

trading contracts are non-hedging derivatives and the change in value is recognized in earnings on a mark-to-market basis.

Interest rate swap contracts are recorded by the Successor as "Other current liabilities" or non-current "Derivative liabilities" on the Balance Sheets. The current and non-current interest rate swap liabilities are calculated by dividing the total interest rate swap liability by the number of years remaining on the contract at the end of the period. The Predecessor classified all interest rate swap liabilities as non-current "Derivative liabilities" on the Balance Sheets. The Successor and Predecessor presentation are both appropriate under GAAP. The Predecessor and Successor determine the classification of energy trading contracts based on the settlement date of the individual contracts. Energy trading contracts classified as current are recognized in "Prepayments and other current assets" or "Other current liabilities" on the Balance Sheets. Energy trading contracts classified as non-current are recognized in "Other assets" or long-term "Derivative liabilities" on the Balance Sheets. Cash inflows and outflows related to derivative instruments are included as a component of operating activity on the Statements of Cash Flows due to the underlying nature of the hedged items.

See Note 5, Derivative Financial Instruments, and Note 6, Fair Value Measurements, for further information on derivative instruments.

The operating revenues line item in the Statements of Income contains revenues from the following:

Revenues are recorded based on service rendered to customers through month-end. Operating revenues are recorded based on energy deliveries through the end of the calendar month. Unbilled retail revenues result because customers' meters are read and bills are rendered throughout the month, rather than all being read at the end of the month. Unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh by the estimated average cents per kWh.

Accounts receivable are reported in the Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts.

The allowance for doubtful accounts included in "Accounts receivable—customer" is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period, multiplied by the retail revenues billed over the last four months. Accounts with no payment activity are charged-off after four months, although collection efforts continue thereafter. The allowance for doubtful accounts included in "Accounts receivable—other" is composed of accounts aged more than four months. Accounts are written off as management determines them uncollectible.

All highly liquid investments with an original maturity of three months or less are considered to be cash equivalents.

Bank deposits and other cash equivalents that are restricted by agreement or that have been clearly designated for a specific purpose are classified as restricted cash. The change in restricted cash is reported as an investing activity on the Statements of Cash Flows. On the Balance Sheets, the current portion of restricted cash is included in "Prepayments and other current assets," and the non-current portion is included in "Other assets." For LG&E, the December 31, 2010, balance of restricted cash is $22 million, consisting primarily of cash collateral posted to counterparties related to LG&E's interest rate swap contracts.

LG&E values certain financial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to derivative assets and liabilities, investments in securities including

investments in the pension and postretirement benefit plans and reacquired bonds and cash and cash equivalents. LG&E uses, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions that market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.

LG&E prioritizes fair value measurements for disclosure by grouping them into one of three levels in the fair value hierarchy. The highest priority is given to measurements using level 1 inputs. The appropriate level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:

Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, LG&E's assessment of the significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy. See Note 5, Derivative Financial Instruments, and Note 6, Fair Value Measurements, for further information on fair value measurements.

At December 31, 2010, LG&E had $163 million of bonds classified as "Long-term debt" on the Balance Sheets that LG&E reacquired. The Successor has classified these bonds as "Available for sale debt securities" because management intended to remarket the bonds at a later date. The Predecessor classified the reacquired bonds as an offset to "Long-term debt" because the Company was no longer obligated to any third party investors. The Predecessor presentation and the Successor presentation are both appropriate under GAAP.

"Available for sale debt securities" are carried at fair value and are classified as current assets on the Balance Sheets. Unrealized gains and losses on all available for sale debt securities are reported, net of tax, in other comprehensive income or recognized in earnings when the decline in fair value below cost is determined to be other-than-temporary impairment. For 2010, LG&E had no unrealized gains or losses on available for sale debt securities.

The criteria for determining whether a decline in fair value of a debt security is other than temporary and whether the other-than-temporary impairment is recognized in earnings or reported in other comprehensive income when the debt security is in an unrealized position is as follows:

LG&E's cost method investment, included in "Other assets" on the Balance Sheets, consists of the Company's investment in OVEC. LG&E and 11 other electric utilities are owners of OVEC, which is located in Piketon, Ohio. OVEC owns and operates two coal-fired power plants, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana with combined nameplate generating capacities of 2,390 Mw. OVEC's power is currently supplied to LG&E and 13 other companies affiliated with the various owners. Pursuant to current contractual agreements, LG&E owns 5.63% of OVEC's common stock and is contractually entitled to 5.63% of OVEC's output. Based on nameplate generating capacity, this would be approximately 134 Mw.

As of December 31, 2010 and 2009, LG&E's investment in OVEC totaled less than $1 million. LG&E is not the primary beneficiary of OVEC; therefore, it is not consolidated into the Company's financial statements and is accounted for under the cost method of accounting. The direct exposure to loss as a result of the Company's involvement with OVEC is generally limited to the value of its investment; however, LG&E may be conditionally responsible for a pro-rata share of certain OVEC obligations. See Note 2, Acquisition by PPL, and Note 13, Commitments and Contingencies, for further discussion regarding purchase accounting adjustments recognized, ownership interest and power purchase rights.

Regulated utility plant was stated at original cost for the Predecessor and adjusted to the net book value on November 1, 2010, the acquisition date for the Successor. LG&E determined that fair value was equal to net book value at the acquisition date since LG&E's operations are conducted in a regulated environment. Original cost includes payroll-related costs such as taxes, fringe benefits and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. LG&E has not recorded any allowance for funds used during construction in accordance with the FERC.

The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.

Included in "Property, plant and equipment" on the Balance Sheets are capitalized costs of software projects that were developed or obtained for internal use. These capitalized costs are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Following are capitalized software costs and the accumulated amortization:

The amortization of capitalized software is included in "Depreciation and amortization" on the Statements of Income.

Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided as a percentage of depreciable plant were approximately:

Of the amount provided for depreciation, the following were related to the retirement, removal and disposal costs of long lived assets:

LG&E performs a quarterly review to determine if an impairment analyses is required for long-lived assets that are subject to depreciation or amortization. This review identifies changes in circumstances indicating that a long-lived asset's carrying value may not be recoverable. An impairment analysis will be performed if warranted, based on the review.

For a long-lived asset to be held and used, impairment exists when the carrying amount exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its fair value.

LG&E, as the result of PPL's acquisition of LKE, recorded the fair value of its coal contracts, emission allowances and OVEC power purchase contract. The difference between the fair value and the cost for these assets is being amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed or otherwise used. When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, LG&E considers the expected use of the asset, the expected useful life of other assets to which the useful life of the intangible asset may relate and legal, regulatory, or contractual provisions that may limit the useful life. See Note 2, Acquisition by PPL, for methods used to determine the long-lived intangible assets' fair values. See Note 7, Goodwill and Intangible Assets, for the fair value amounts and amortization periods. The current intangible assets and long-term intangible assets are included in "Other intangible assets" on the Balance Sheets.

The Predecessor reported emission allowances in "Other materials and supplies" on the Balance Sheets. The emission allowances were not amortized; rather, they were expensed when consumed. The Predecessor did not recognize the coal contracts or the OVEC power purchase contract, as these intangible assets were not derivatives.

In connection with PPL's acquisition of LKE, LG&E recorded goodwill on November 1, 2010. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is tested annually for impairment during the fourth quarter, or more frequently if management determines that a triggering event may have occurred that would more likely than not reduce the fair value of an operating unit below its carrying value. Goodwill impairment charges are not subject to rate recovery. See Note 7, Goodwill and Intangible Assets, for further discussion regarding the Company's goodwill and current test results.

LG&E recognizes various legal obligations associated with the retirement of long-lived assets as liabilities in the financial statements. Initially this obligation is measured at fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statements of Income, for changes in the obligation due to the passage of time. An offsetting regulatory asset is recognized to reverse the depreciation and accretion expense related to the ARO such that there is no income statement impact. The regulatory asset is relieved when the ARO has been settled. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the obligations. See Note 4, Asset Retirement Obligations, for further information on AROs.

LG&E employees benefit from both funded and unfunded retirement benefit plans . An asset or liability is recorded to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets or regulatory liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.

The expected return on plan assets is determined based on the current level of expected return on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class is then weighted based on the current asset allocation.

The discount rate used for pensions, postretirement and post-employment plans by the Predecessor was determined using the Mercer Yield Curve. The expected return on assets assumption was 7.75%. Gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or market value of assets were amortized on a straight-line basis over the average future service period of active participants. The market-related value of assets was equal to the fair market value of the assets.

The discount rate used by the Successor was determined by the Towers Watson Yield Curve based on the individual plan cash flows. The expected return on assets was reduced from 7.75% to 7.25%. The amortization period for the recognition of gains and losses for retirement plans was changed to reflect the Successor's amortization policy. Under the Successor's method, gains and losses in excess of 10% but less than 30% of the greater of the plan's projected benefit obligation or market-related value of assets, are amortized on a straight-line basis over the average future service period of active participants. Gains and losses in excess of 30% of the plan's projected benefit obligation or market-related value of assets are amortized on a straight-line basis over a period equal to one-half of the average future service period of active participants. The market-related value of assets for the qualified retirement plans will be equal to a five year smoothed asset value. Gains and losses in excess of the expected return will be phased-in over a five year period, prospectively from November 1, 2010.

See Note 9, Pension and Other Postretirement Benefit Plans, for further information.

Potential losses are accrued when information is available that indicates it is "probable" that a loss has been incurred, given the likelihood of uncertain future events, and the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." LG&E continuously assesses potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events.

LG&E does not record the accrual of contingencies that might result in gains unless recovery is assured.

For the periods ended on or before October 31, 2010, LG&E was a subsidiary of E.ON U.S. and was part of E. ON U.S.'s direct parent's, E.ON US Investments Corp., consolidated U.S. federal income tax return. On November 1, 2010, LG&E became a part of PPL's consolidated U.S. federal income tax return.

Significant management judgment is required in developing LG&E's provision for income taxes primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

LG&E evaluates tax positions following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements of LG&E.

Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, as well as the tax effects of net operating losses and tax credit carryforwards.

LG&E records valuation allowances to reduce deferred tax assets to the amounts that are more likely than not to be realized. LG&E considers the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies in initially recording and subsequently reevaluating the need for valuation allowances. If LG&E determines that it is able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made. Likewise, if LG&E determines that it is not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made.

The provision for LG&E's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the regulators. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included on the Balance Sheets in "Regulatory liabilities."

LG&E defers investment tax credits when the credits are utilized and amortizes the deferred amounts over the average lives of the related assets.

LG&E evaluates whether arrangements entered into contain leases for accounting purposes.

Fuel, natural gas stored underground and other materials and supplies inventories are accounted for using the average-cost method.

The cost of fuel for electric generation is charged to expense as used and the cost of natural gas supply is charged to expense as delivered to the distribution system. LG&E operates under a Kentucky Commission approved PBR mechanism related to natural gas procurement activity. See Note 3, Rates and Regulatory Matters, for a description of the FAC and GSC.

The Company's long-term debt includes $120 million of pollution control bonds, which are subject to tender for purchase at the option of the holder and to mandatory tender for purchase on the occurrence of certain events. The Successor has classified these bonds as long term because the Company has the intent and ability to utilize its $400 million credit facility, which matures in December 2014, to fund any mandatory purchases. Predecessor classified these bonds as the current portion of long-term debt due to the tender for purchase provisions. The Predecessor presentation and the Successor presentation are both appropriate under GAAP. See Note 11, Long-Term Debt, and Note 12, Notes Payable and Other Short-Term Obligations, for more information on the Company's debt and credit facilities.

Debt expense is capitalized and amortized over the lives of the related bond issues using the straight-line method, which approximates the effective interest method. Depending on the type of expense, the Successor capitalized debt expenses in long-term other regulatory assets or long-term other assets to align with the term of the debt the expenses were related. The Predecessor capitalized debt expenses in current or long-term other regulatory assets or other current or long-term other assets based on the amount of expense expected to be recovered within the next year through rate recovery. Both the Predecessor and the Successor amortize debt expenses over the lives of the related bond issues. The Predecessor presentation and the Successor presentation are both appropriate under regulatory practices and GAAP.

In January 2010, the FASB issued guidance related to fair value measurement disclosures requiring separate disclosure of amounts of significant transfers in and out of level 1 and level 2 fair value measurements and separate information about purchases, sales, issuances and settlements within level 3 measurements. This guidance is effective for the interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about the roll-forward of activity in level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. This guidance has no impact on the Company's results of operations, financial position, liquidity or disclosures.

On November 1, 2010, PPL completed its acquisition of LKE and its subsidiaries. The push-down basis of accounting was used to record the fair value adjustments of assets and liabilities on LKE at the acquisition date. PPL paid a cash consideration for LKE and its subsidiaries of $2,493 million as well as a capital contribution on November 1, 2010, of $1,565 million; included within this was the consideration paid for LG&E of $1,702 million. The allocation of the LG&E purchase price was based on the fair value of assets acquired and liabilities assumed.

The allocation of the purchase price to the fair value of assets acquired and liabilities assumed is as follows:


Current assets	$	546
Investments		1
Property, plant and equipment		2,935
Other intangible assets		183
Regulatory and other non-current assets		416
Current liabilities		(420	)
Affiliated debt		(485	)
Debt		(580	)
Other non-current liabilities		(1,283	)

Net identifiable assets acquired		1,313
Goodwill		389

Total purchase price	$	1,702

Goodwill represents value paid for the rate regulated business of LG&E, which is located in a defined service area with a constructive regulatory environment, which provides for future investment, earnings and cash flow growth, as well as the talented and experienced workforce. LG&E's franchise values are being attributed to the going concern value of the business, and thus were recorded as goodwill rather than a separately identifiable intangible asset. None of the goodwill recognized is deductible for income tax purposes or included in regulated customer rates.

Adjustments to LG&E's assets and liabilities that contributed to goodwill were as follows:

The pollution control bonds, excluding the reacquired bonds, had a fair market value adjustment of $7 million. All variable bonds were valued at par while the fixed rate bonds were valued with a yield curve based on average credit spreads for similar bonds.

As a result of the purchase accounting associated with the acquisition, the following items had a fair value adjustment but no effect on goodwill as the offset was either a regulatory asset or liability. The regulatory asset or liability has been recorded to eliminate any ratemaking impact of the fair value adjustments:

The fair value of intangible assets and liabilities (e.g. contracts that have favorable or unfavorable terms relative to market), including coal contracts and power purchase agreements, as well as emission allowances, have been reflected on the Balance Sheets with offsetting regulatory assets or liabilities. Prior to the acquisition, LG&E recovered the cost of the coal contracts, power purchases and emission allowances and this rate treatment will continue after the acquisition. As a result, management believes the regulatory assets and liabilities created to offset the fair value adjustments meet the recognition criteria established by existing accounting guidance and eliminate any ratemaking impact of the fair value adjustments. LG&E's customer rates will continue to reflect these items (e.g. coal, purchased power, emission allowances) at their original contracted prices.

LG&E also considered whether a separate fair value should be assigned to LG&E's rights to operate within its various electric and natural gas distribution service areas but concluded that these rights only provided the opportunity to earn a regulated return and barriers to market entry, which in

management's judgment is not considered a separately identifiable intangible asset under applicable accounting guidance; rather, it is considered going-concern value, or goodwill.

The Company is subject to the jurisdiction of the FERC and Kentucky Commission in virtually all matters related to electric and natural gas utility regulation and as such, its accounting is subject to the regulated operations guidance of the FASB ASC. Given its position in the marketplace and the status of regulation in Kentucky, there are no plans or intentions to discontinue the application of the regulated operations guidance of the FASB ASC.

LG&E's base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain regulatory adjustments to exclude non-regulated investments and environmental compliance plans recovered separately through the ECR mechanism. No regulatory assets or regulatory liabilities recorded at the time base rates were determined were excluded from the return on capitalization utilized in the calculation of Kentucky base rates. Therefore, a return is earned on all Kentucky regulatory assets existing at the time base rates were determined, except where such regulatory assets were offset by associated liabilities and thus, have no net impact on capitalization.

As a result of purchase accounting, certain fair value amounts, reflecting contracts that have favorable or unfavorable terms relative to market, were recorded on the Balance Sheets with offsetting regulatory assets or liabilities. Prior to the acquisition, LG&E recovered in customer rates the cost of the coal contracts, power purchases and emission allowances and this rate treatment will continue after the recognition criteria established by existing accounting guidance and eliminate any ratemaking impact of the fair value adjustments. LG&E's customer rates will continue to reflect these items (e.g. coal, purchased power, emission allowances) at their original contracted prices.

On April 28, 2010, E.ON U.S. announced that a Purchase and Sale Agreement (the "Agreement") had been entered into among E.ON US Investments Corp., PPL and E.ON.

The transaction was subject to customary closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act, receipt of required regulatory approvals (including state regulators in Kentucky and the FERC) and the absence of injunctions or restraints imposed by governmental entities.

Change of control and financing-related applications were filed on May 28, 2010 with the Kentucky Commission. An application with the FERC was filed on June 28, 2010. During the second quarter of 2010, a number of parties were granted intervenor status in the Kentucky Commission proceedings and data request filings and responses occurred. Early termination of the Hart-Scott-Rodino waiting period was received on August 2, 2010.

A hearing in the Kentucky Commission proceedings was held on September 8, 2010 at which time a unanimous settlement agreement was presented. In the settlement, LG&E committed that no base rate increases would take effect before January 1, 2013. The LG&E rate increases that took effect on August 1, 2010, were not impacted by the settlement. Under the terms of the settlement, LG&E retains the right to seek approval for the deferral of "extraordinary and uncontrollable costs." Interim rate adjustments will continue to be permissible during that period for existing fuel, environmental and

demand-side management cost trackers. The agreement also substitutes an acquisition savings shared deferral mechanism for the requirement that the Utilities file a synergies plan with the Kentucky Commission. This mechanism, which will be in place until the earlier of five years or the first day of the year in which a base rate increase becomes effective, permits LG&E to earn up to a 10.75% return on equity. Any earnings above a 10.75% return on equity will be shared with customers on a 50%/50% basis. On September 30, 2010, the Kentucky Commission issued an Order approving the transfer of ownership of LG&E via the acquisition of E.ON U.S. by PPL, incorporating the terms of the submitted settlement. The Commission's Orders contained a number of other commitments with regard to operations, workforce, community involvement and other matters.

In mid-September 2010, LG&E and other applicants in the FERC change of control proceeding reached an agreement with the protesters, whereby such protests were withdrawn. The agreement, which was filed for consideration with the FERC, includes various conditional commitments, such as a continuation of certain existing undertakings with protesters in prior cases, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that LG&E agreed not to seek the same transaction-related cost from retail customers and agreements to coordinate with protesters in certain open or ongoing matters. A FERC Order approving the transaction was received on October 26, 2010 and the transaction was completed November 1, 2010.

In January 2010, LG&E filed an application with the Kentucky Commission requesting an increase in electric base rates of approximately 12%, or $95 million annually, and its natural gas base rates of approximately 8%, or $23 million annually. In June 2010, LG&E and all of the intervenors, except the AG, agreed to stipulations providing for increases in electric base rates of $74 million annually and natural gas base rates of $17 million annually and filed a request with the Kentucky Commission to approve such settlement. An Order in the proceeding was issued in July 2010, approving all the provisions in the stipulations, including a return on equity range of 9.75%-10.75%. The new rates became effective on August 1, 2010.

In July 2008, LG&E filed an application with the Kentucky Commission requesting increases in electric and natural gas base rates. In January 2009, LG&E, the AG, the KIUC and all other parties to the rate cases filed a settlement agreement with the Kentucky Commission, under which LG&E's natural gas base rates increased by $22 million annually and its electric base rates decreased by $13 million annually. An Order approving the settlement agreement was received in February 2009. The new rates were implemented effective February 6, 2009.

The following regulatory assets and liabilities were included in the Balance Sheets as of December 31:



				Successor		Predecessor
				2010		2009
Current regulatory assets:
	GSC and PBR(a)			$	4	$	3
	ECR(b)				5		7
	FAC(b)				3		—
	Coal contracts(c)				1		—
	MISO exit(d)				—		1
	Other(e)				—		3

Total current regulatory assets				$	13	$	14

Non-current regulatory assets:
	Pension and postretirement benefits(f)			$	213	$	204
	Other non-current regulatory assets:
		Storm restoration(d)			65		67
		Mark to market impact of interest rate swaps(g)			34		—
		ARO(h)			7		30
		Unamortized loss on bonds(d)			22		22
		Swap termination(d)			9		—
		Coal contracts(c)			8		—
		Unamortized debt expense			4		—
		MISO exit(d)			1		4
		Other(e)			4		2

			Subtotal other non-current regulatory assets		154		125

Total non-current regulatory assets				$	367	$	329

Current regulatory liabilities:
	Coal contracts			$	31	$	—
	GSC				9		34
	DSM				5		4
	Emission allowances				6		—

Total current regulatory liabilities				$	51	$	38

Non-current regulatory liabilities:
	Accumulated cost of removal of utility plant			$	275	$	259
	Other non-current regulatory liabilities:
		Coal contracts			87		—
		OVEC power purchase contract			86		—
		Deferred income taxes—net			34		41
		Other(i)			1		3

			Subtotal other non-current regulatory liabilities		208		44

Total non-current regulatory liabilities				$	483	$	303

(b)

The FAC and ECR regulatory assets have separate recovery mechanisms with recovery within twelve months.

(c)

Offsetting regulatory assets or liabilities for fair value purchase accounting adjustments. See Note 2, Acquisition by PPL, for information on the purchase accounting adjustments.

(d)

These regulatory assets are recovered through base rates.

(e)

Other regulatory assets include:

•: Mill Creek Ash Pond costs, which were recovered through base rates.
•: The CMRG and KCCS contributions, an EKPC FERC transmission settlement agreement and rate case expenses, which are recovered through base rates.
•: Offsetting regulatory asset for fair value purchase accounting adjustment for leases. See Note 2, Acquisition by PPL, for information on the purchase accounting adjustments.

(f)

LG&E generally recovers this asset through pension expense included in the calculation of base rates.

(g)

Beginning in the third quarter of 2010, based on an Order from the Kentucky Commission in the 2010 rate case whereby the cost of a terminated rate swap was allowed to be recovered in base rates, the mark-to-market impact of the effective and ineffective interest rate swaps is considered probable of recovery through rates and therefore included in regulatory assets. See Note 5, Derivative Financial Instruments, for further discussion.

(h)

When an asset with an ARO is retired, the related ARO regulatory asset will be offset against the associated ARO regulatory liability, ARO asset and ARO liability.

(i)

Other regulatory liabilities include the emission allowance purchase accounting offset and MISO exit.

LG&E's natural gas rates contain a GSC, whereby increases and decreases in the cost of natural gas supply are reflected in LG&E's rates, subject to approval by the Kentucky Commission. The GSC procedure prescribed by Order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of natural gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of natural gas supply cost from prior quarters is to be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.

LG&E's GSC was modified in 1997 to incorporate a natural gas procurement incentive mechanism. Since November 1, 1997, LG&E has operated under this PBR mechanism related to its natural gas procurement activities. LG&E's rates are adjusted annually to recover (or refund) its portion of the expense (or savings) incurred during each PBR year (12 months ending October 31). Pursuant to the extension of LG&E's natural gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under the PBR requires savings and expenses to be shared 25% with shareholders and 75% with customers up to 4.5% of the benchmarked natural gas costs. Savings and expenses in excess of 4.5% of the benchmarked natural gas costs are shared 50% with shareholders and 50% with customers. The current natural gas supply cost PBR mechanism was extended through 2010 without further modification. In December 2009, LG&E filed an application with the Kentucky Commission to extend and modify its existing natural gas cost PBR. The current PBR was set to expire at the end of October 2010. In April 2010, the Kentucky Commission issued an Order approving a five year extension and the requested minor modifications to the PBR effective November 2010.

During the PBR years ending in 2010, 2009 and 2008, LG&E achieved $8 million, $7 million and $11 million in savings, respectively. In 2010, 2009 and 2008, of the total savings amount, LG&E's portion was approximately $2 million, $2 million and $3 million, respectively, and the customers' portion was approximately $6 million in 2010, $5 million in 2009 and $8 million in 2008.

LG&E recovers the costs of complying with the Federal Clean Air Act pursuant to Kentucky Revised Statute 278-183 as amended and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal, through the ECR mechanism. The amount of the regulatory asset or liability is the amount that has been under-or over-recovered due to timing or adjustments to the mechanism.

The Kentucky Commission requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. In December 2010, the Kentucky Commission initiated a six-month review of the Utilities' environmental surcharge for the billing period ending October 2010. An order is expected in the second quarter of 2011. Also, in December 2010, an Order was issued approving the charges and credits billed through the ECR during the six-month period ending April 2010, as well as approving billing adjustments for under-recovered costs and the rate of return on capital. In May 2010, an Order was issued approving the amounts billed through the ECR during the six-month period ending October 2009 and the rate of return on capital and allowing recovery of the under-recovery position in subsequent monthly filings. In December 2009, an Order was issued approving the charges and credits billed through the ECR during the two-year period ending April 2009, an increase in the jurisdictional revenue requirement, a base rate roll-in and a revised rate of return on capital. In July 2009, an Order was issued approving the charges and credits billed through the ECR during the six-month period ending October 2008, as well as approving billing adjustments for under-recovered costs and the rate of return on capital. In August 2008, an Order was issued approving the charges and credits billed through the ECR during the six-month periods ending April 2008 and October 2007 and the rate of return on capital. In March 2008, an Order was issued approving the charges and credits billed through the ECR during the six-month and two-year periods ending October 2006 and April 2007, respectively, as well as approving billing adjustments, roll-in adjustments to base rates, revisions to the monthly surcharge filing and the rates of return on capital.

In June 2009, the Company filed an application for a new ECR plan with the Kentucky Commission seeking approval to recover investments in environmental upgrades and operations and maintenance costs at the Company's generating facilities. During 2009, LG&E reached a unanimous settlement with all parties to the case and the Kentucky Commission issued an Order approving LG&E's application. Recovery on customer bills through the monthly ECR surcharge for these projects began with the February 2010 billing cycle.

In February 2009, the Kentucky Commission approved a settlement agreement in the rate case which provides for an authorized return on equity applicable to the ECR mechanism of 10.63% effective with the February 2009 expense month filing, which represents a slight increase over the previously authorized 10.50%. The 10.63% return on equity for the ECR mechanism was affirmed in the 2010 rate case.

LG&E's retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. The FAC allows the Company to adjust billed amounts for the difference between the fuel cost component of base rates and the actual fuel cost, including transportation costs. Refunds to customers occur if the actual costs are below the embedded cost component. Additional charges to customers occur if the actual costs exceed the embedded cost component. The amount of the regulatory asset or liability is the amount that has been under- or over-recovered due to timing or adjustments to the mechanism.

The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. In December 2010, May 2010, November 2009, January 2009, May 2008 and January 2008 the Kentucky Commission issued Orders approving the charges and credits billed through the FAC for the six-month periods ending April 2010, August 2009, April 2009, April 2008, October 2007 and April 2007, respectively. In January 2009, the Kentucky Commission initiated routine examinations of the FAC for the two-year period November 1, 2006 through October 31, 2008. The Kentucky Commission issued an Order in June 2009 approving the charges and credits billed through the FAC during the review period.

In November 2010, purchase accounting adjustments were recorded for the fair value of LG&E's coal contracts. Offsetting regulatory assets or liabilities for fair value purchase accounting adjustments eliminate any ratemaking impact of the fair value adjustments.

Following receipt of applicable FERC, Kentucky Commission and other regulatory Orders, related to proceedings that had been underway since July 2003, LG&E withdrew from the MISO effective September 1, 2006. Since the exit from the MISO, LG&E has been operating under a FERC approved OATT. LG&E now contracts with the TVA to act as its transmission reliability coordinator and SPP to function as its independent transmission operator, pursuant to FERC requirements. The contractual obligations with the TVA extend through August 2011 and with SPP through August 2012.

LG&E and the MISO agreed upon overall calculation methods for the contractual exit fee to be paid by the Company following its withdrawal. In October 2006, the Company paid $13 million to the MISO and made related FERC compliance filings. The Company's payment of this exit fee was with reservation of its rights to contest the amount, or components thereof, following a continuing review of its calculation and supporting documentation. LG&E and the MISO resolved their dispute regarding the calculation of the exit fee and, in November 2007, filed an application with the FERC for approval of a recalculation agreement. In March 2008, the FERC approved the parties' recalculation of the exit fee, as well as the approved agreement providing LG&E with recovery of $2 million, of which $1 million was immediately recovered in 2008, with the remainder to be recovered over the seven years from 2008 through 2014 for credits realized from other payments the MISO will receive, plus interest.

In accordance with Kentucky Commission Orders approving the MISO exit, LG&E established a regulatory asset for the MISO exit fee, net of former MISO administrative charges collected via base

rates through the base rate case test year ended April 30, 2008. The net MISO exit fee is subject to adjustment for possible future MISO credits and a regulatory liability for certain revenues associated with former MISO administrative charges, which were collected via base rates until February 6, 2009. The approved 2008 base rate case settlement provided for MISO administrative charges collected through base rates from May 1, 2008 to February 6, 2009 and any future adjustments to the MISO exit fee, to be established as a regulatory liability until the amounts can be amortized in future base rate cases. This regulatory liability balance as of October 31, 2009 was included in the base rate case application filed on January 29, 2010. MISO exit fee credit amounts subsequent to October 31, 2009, will continue to accumulate as a regulatory liability until they can be amortized in future base rate cases.

In November 2008, the FERC issued Orders in industry-wide proceedings relating to MISO RSG calculation and resettlement procedures. RSG charges are amounts assessed to various participants active in the MISO trading market which generally seek to compensate for uneconomic generation dispatch due to regional transmission or power market operational considerations, with some customer classes eligible for payments, while others may bear charges. The FERC Orders approved two requests for significantly altered formulas and principles, each of which the FERC applied differently to calculate RSG charges for various historical and future periods. Based upon the 2008 FERC Orders, the Company established a reserve during the fourth quarter of 2008 of $2 million relating to potential RSG resettlement costs for the period ended December 31, 2008. However, in May 2009, after a portion of the resettlement payments had been made, the FERC issued an Order on the requests for rehearing on one November 2008 Order, which changed the effective date and reduced almost all of the previously accrued RSG resettlement costs. Therefore, these costs were reversed and a receivable was established for amounts already paid of $1 million. The MISO began refunding the amounts to the Company in June 2009, with full repayment in September 2009. In June 2009, the FERC issued an Order in the rate mismatch RSG proceeding, stating it will not require resettlements of the rate mismatch calculation from April 1, 2005 to November 4, 2007. An accrual had previously been recorded in 2008 for the rate mismatch issue for the time period April 25, 2006 to August 9, 2007, but no accrual had been recorded for the time period November 5, 2007 to November 9, 2008 based on the prior Order. Accordingly, the accrual for the former time period was reversed and an accrual for the latter time period was recorded in June 2009, with a net effect of less than $1 million of expense, substantially all of which was paid by September 2009.

In August 2009, the FERC determined that the MISO had failed to demonstrate that its proposed exemptions to real-time RSG charges were just and reasonable. In November 2009, the MISO made a compliance filing incorporating the rulings of the FERC Orders and a related task force, with a primary open issue being whether certain of the tariff changes are applied prospectively only or retroactively to approximately January 6, 2009.

In November 2009, the Utilities filed an application with the FERC to approve certain independent transmission operator arrangements to be effective upon the expiration of their current contract with SPP in September 2010. The application sought authority for LG&E and KU to function after such date as the administrators of their own OATT for most purposes. However, due to the lack of FERC approval for such an approach and the approaching expiration of the SPP contract, the Utilities determined the approach was no longer reasonably achievable without unacceptable delay and uncertainty. In July 2010, the Utilities entered into a new agreement with SPP to provide independent transmission operator services for a specified, limited time and removed its application for authority of

administering its own OATT. The TVA, which currently acts as reliability coordinator, has also been retained under the existing service contract. The new agreement extends TVA services to August 2011 with no alterations or changes to the party's duties or responsibilities.

In August 2010, the FERC issued three Orders accepting most facets of several MISO RSG compliance filings. The FERC ordered the MISO to issue refunds for RSG charges that were imposed by the MISO on the assumption that there were rate mismatches for the period beginning November 5, 2007 through the present. There is no financial statement impact to the Company from this Order, as the MISO had anticipated that the FERC would require these refunds and had preemptively included them in the resettlements paid in 2009. The FERC denied the MISO's proposal to exempt certain resources from RSG charges, effective prospectively. The FERC accepted portions and rejected portions of the MISO's proposed RSG Rate Redesign Proposal, which will be effective when the software is ready for implementation subject to further compliance filings. The impact of the Redesign Proposal on the Company cannot be estimated at this time.

LG&E accounts for pension and postretirement benefits in accordance with the compensation—retirement benefits guidance of the FASB ASC. This guidance requires employers to recognize the over-funded or under-funded status of a defined benefit pension and postretirement plan as an asset or liability on the Balance Sheets and to recognize through other comprehensive income the changes in the funded status in the year in which the changes occur. Under the regulated operations guidance of the FASB ASC, LG&E can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current rate recovery in Kentucky is based on the compensation—retirement benefits guidance of the FASB ASC. Regulators have been clear and consistent with their historical treatment of such rate recovery; therefore, the Company has recorded a regulatory asset representing the change in funded status of its pension and postretirement benefit plans that is expected to be recovered. The regulatory asset will be adjusted annually as prior service cost and actuarial gains and losses are recognized in net periodic benefit cost.

In January 2009, a significant ice storm passed through LG&E's service area causing approximately 205,000 customer outages, followed closely by a severe wind storm in February 2009, causing approximately 37,000 customer outages. An application was filed with the Kentucky Commission in April 2009, requesting approval to establish a regulatory asset and defer for future recovery, approximately $45 million in incremental operation and maintenance expenses related to the storm restoration. In September 2009, the Kentucky Commission issued an Order allowing the establishment a regulatory asset of up to $45 million based on actual costs for storm damages and service restoration due to the January and February 2009 storms. In September 2009, a regulatory asset of $44 million was established for actual costs incurred and approval was received in LG&E's 2010 base rate case to recover this asset over a ten year period beginning August 1, 2010.

In September 2008, high winds from the remnants of Hurricane Ike passed through the service area causing significant outages and system damage. In October 2008, an application was filed with the Kentucky Commission requesting approval to establish a regulatory asset and defer for future recovery approximately $24 million of expenses related to the storm restoration. In December 2008, the Kentucky Commission issued an Order allowing the establishment of a regulatory asset of up to $24 million based on actual costs for storm damages and service restoration due to Hurricane Ike. In December 2008, a regulatory asset of $24 million was established for actual costs incurred and LG&E received approval in its 2010 base rate case to recover this asset over a ten year period, beginning August 1, 2010.

Interest rate swaps are accounted for on a fair value basis in accordance with the derivatives and hedging guidance of the FASB ASC. Beginning in the third quarter of 2010, the unrealized gains and losses of the effective and ineffective interest rate swaps are included in a regulatory asset based on an Order from the Kentucky Commission in the 2010 rate case whereby the cost of a terminated swap was allowed to be recovered in base rates. Previously, interest rate swaps designated as effective cash flow hedges had resulting gains and losses recorded within other comprehensive income and common equity. The ineffective portion of interest rate swaps designated as cash flow hedges was previously recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps. LG&E is able to recover the unrealized gains and losses on the interest rate swaps under its existing rate recovery structure as the interest expense on the swaps is realized.

The costs of early extinguishment of debt, including call premiums, legal and other expenses and any unamortized balance of debt expense are amortized using the straight-line method, which approximates the effective interest method, over the life of either the replacement debt (in the case of refinancing) or the original life of the extinguished debt.

In July 2008, LG&E and KU, along with Duke Energy Kentucky, Inc. and Kentucky Power Company, filed an application with the Kentucky Commission requesting approval to establish regulatory assets related to contributions to the CMRG for the development of technologies for reducing carbon dioxide emissions and the KCCS to study the feasibility of geologic storage of carbon dioxide. The filing companies proposed that these contributions be treated as regulatory assets to be deferred until recovery is provided in the next base rate case of each company, at which time the regulatory assets will be amortized over the life of each project: four years with respect to the KCCS and ten years with respect to the CMRG. LG&E and KU jointly agreed to provide $2 million over two years to the KCCS and up to $2 million over ten years to the CMRG. In October 2008, an Order approving the establishment of the requested regulatory assets was received. LG&E received approval from the Kentucky Commission in the Company's 2010 Kentucky base rate case to recover these regulatory assets over the requested period beginning August 1, 2010.

LG&E incurred $1 million in expenses related to the development and support of the 2008 Kentucky base rate case. The Kentucky Commission approved the establishment of a regulatory asset for these expenses and authorized amortization over three years beginning in March 2009.

LG&E incurred $1 million in expenses related to the development and support of the 2010 Kentucky base rate case. The Kentucky Commission approved the establishment of a regulatory asset for these expenses and authorized amortization over three years beginning in August 2010.

DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's rates contain a DSM provision which includes a rate mechanism that provides for concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. The provision allows LG&E to recover revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

In July 2007, LG&E and KU filed an application with the Kentucky Commission requesting an order approving enhanced versions of the existing DSM programs along with the addition of several new cost effective programs. The total annual budget for these programs is approximately $26 million. In March 2008, the Kentucky Commission issued an Order approving the application, with minor modifications. LG&E and KU filed revised tariffs in April 2008, under authority of this Order, which were effective in May 2008.

In November 2010, purchase accounting adjustments were recorded for fair market value LG&E's SO2, NOx ozone season and NOx annual emission allowances. Offsetting regulatory assets or liabilities for fair value purchase accounting adjustments eliminate any ratemaking impact of the fair value adjustments. LG&E is granted SO2 emission allowances through 2040 and NOx ozone season and NOx annual emission allowances through 2011.

As of December 31, 2010 and 2009, LG&E segregated the cost of removal, previously embedded in accumulated depreciation, of $275 million and $259 million, respectively, in accordance with FERC Order No. 631. For reporting purposes on the Balance Sheets, LG&E presented this cost of removal as a "Regulatory liability" pursuant to the regulated operations guidance of the FASB ASC.

In November 2010, purchase accounting adjustments were recorded for the fair value of the power purchase agreement between LG&E and OVEC. Offsetting regulatory liabilities for fair value purchase accounting adjustments eliminate any ratemaking impact of the fair value adjustments.

These regulatory liabilities represent the future revenue impact from the reversal of deferred income taxes required for unamortized investment tax credits and deferred taxes provided at rates in excess of currently enacted rates.

In November 2009, the Kentucky Commission issued a report following review and analysis of the effects and utility response to the September 2008 wind storm and the January 2009 ice storm and possible utility industry preventative measures relating thereto. The report suggested a number of proposed or recommended preventative or responsive measures, including consideration of selective hardening of facilities, altered vegetation management programs, enhanced customer outage communications and similar measures. In March 2010, the Utilities filed a joint response reporting on their actions with respect to such recommendations. The response indicated implementation or completion of substantially all of the recommendations, including, among other matters, on-going reviews of system hardening and vegetation management procedures, certain test or pilot programs in such areas and fielding of enhanced operational and customer outage-related systems.

In August 2009, LG&E and KU filed a notice of intent with the Kentucky Commission indicating their intent to file an application for approval of wind power purchase contracts and cost recovery mechanisms. The contracts were executed in August 2009 and were contingent upon LG&E and KU receiving acceptable regulatory approvals. Pursuant to the proposed 20-year contracts, LG&E and KU would jointly purchase respective assigned portions of the output of two Illinois wind farms totaling an aggregate 109.5 Mw. In September 2009, the Utilities filed an application and supporting testimony with the Kentucky Commission. In October 2009, the Kentucky Commission issued an Order denying the Utilities' request to establish a surcharge for recovery of the costs of purchasing wind power. The Kentucky Commission stated that such recovery constitutes a general rate adjustment and is subject to the regulations of a base rate case. The Kentucky Commission Order provided for the request for approval of the wind power agreements to proceed independently from the request to recover the costs thereof via surcharges. In November 2009, LG&E and KU filed for rehearing of the Kentucky Commission's Order and requested that the matters of approval of the contract and recovery of the costs thereof remain the subject of the same proceeding. During December 2009, the Kentucky Commission issued data requests on this matter. In March 2010, LG&E and KU delivered notices of termination under provisions of the wind power contracts. The Utilities also filed a motion with the Kentucky Commission noting the termination of the contracts and seeking withdrawal of their application in the related regulatory proceeding. In April 2010, the Kentucky Commission issued an Order allowing the Utilities to withdraw their pending application.

In July 2009, the Utilities notified the Kentucky Commission of the proposed sale from the Utilities of certain ownership interests in certain existing Trimble County generating station assets which were anticipated to provide joint or common use in support of the jointly-owned TC2 generating

unit under construction at the station. The undivided ownership interests sold provide KU an ownership interest in these common assets proportional to its interest in TC2 and the assets' role in supporting both TC1 and TC2. In December 2009, LG&E and KU completed the sale transaction at a price of $48 million, representing the current net book value of the assets multiplied by the proportional interest being sold.

In August 2009, the Utilities jointly filed an application with the Kentucky Commission to approve new depreciation rates for applicable jointly-owned TC2-related generating, pollution control and other plant equipment and assets. During December 2009, the Kentucky Commission extended the data discovery process through January 2010 and authorized the Utilities on an interim basis to begin using the depreciation rates for TC2 as proposed in the application. In March 2010, the Kentucky Commission issued a final Order approving the use of the proposed depreciation rates on a permanent basis.

An application for a CCN for construction of TC2 was approved by the Kentucky Commission in November 2005. CCNs for two transmission lines associated with TC2 were issued by the Kentucky Commission in September 2005 and May 2006. All regulatory approvals and rights of way for one transmission line have been obtained.

LG&E's and KU's CCN for a transmission line associated with the TC2 construction has been challenged by certain property owners in Hardin County, Kentucky. Certain proceedings relating to CCN challenging and federal historic preservation permit requirements have concluded with outcomes in the Utilities' favor.

Completion of the transmission lines are also subject to standard construction permit, environmental authorization and real property or easement acquisition procedures and certain Hardin County landowners have raised challenges to the transmission line in some of these forums as well.

With respect to the remaining on-going dispute, LG&E's affiliate, KU obtained various successful rulings during 2008 at the Hardin County Circuit Court confirming its condemnation rights. In August 2008, several landowners appealed such rulings to the Kentucky Court of Appeals and received a temporary stay preventing KU from accessing their properties. In May 2010, the Kentucky Court of Appeals issued an Order affirming the Hardin Circuit Court's finding that KU had the right to condemn easements on the properties. In May 2010, the landowners filed a petition for reconsideration with the Court of Appeals. In July 2010, the Court of Appeals denied that petition. In August 2010, the landowners filed for discretionary review of that denial by the Kentucky Supreme Court.

Settlement discussions with the Hardin County property owners involved in the appeals of the condemnation proceedings have been unsuccessful to date. During the fourth quarter of 2008, LG&E and KU entered into settlements with certain Meade County landowners and obtained dismissals of prior litigation they brought challenging the same transmission line.

As a result of the aforementioned unresolved litigation delays encountered in obtaining access to certain properties in Hardin County, KU obtained easements to allow construction of temporary transmission facilities, bypassing those properties while the litigated issues are resolved. In September 2009, the Kentucky Commission issued an Order stating that a CCN was necessary for two segments of the proposed temporary facilities. In December 2009, the Kentucky Commission granted the CCNs for

the relevant segments and the property owners have filed various motions to intervene, stay and appeal certain elements of the Kentucky Commission's recent Orders. In January 2010, in respect of two of such proceedings, the Franklin County circuit court issued Orders denying the property owners' request for a stay of construction and upholding the prior Kentucky Commission denial of their intervenor status.

Consistent with the regulatory authorizations and the favorable outcome of the legal proceedings, the Utilities completed construction activities on the permanent transmission line easements. During 2010, the Utilities placed the transmission line into operation. While the Utilities are not currently able to predict the ultimate outcome and possible financial effects of the remaining legal proceedings, the Utilities do not believe the matter involves relevant or continuing risks to operations.

In August 2006, LG&E filed an application with the Kentucky Commission requesting approval for the sale of property to the Louisville Arena Authority which was granted in a September 2006 Order. In November 2006, LG&E completed certain agreements pursuant to its August 2006 Memorandum of Understanding with the Louisville Arena Authority regarding the proposed construction of an arena in downtown Louisville. LG&E entered into a relocation agreement with the Louisville Arena Authority providing for reimbursement to LG&E of the costs to be incurred in relocating certain LG&E facilities related to the arena transaction of approximately $63 million. As of December 31, 2010, approximately $62 million of the total costs have been received. The relocation work was substantially completed during 2009, with follow up work continuing in 2010 and 2011. The parties further entered into a property sale contract providing for LG&E's sale of a downtown site to the Louisville Arena Authority which was completed for $9 million in September 2008.

In July 2006, the FERC issued an Order in LG&E's market-based rate proceeding accepting the Company's further proposal to address certain market power issues the FERC claimed would arise upon an exit from the MISO. In particular, the Company received permission to sell power at market-based rates at the interface of balancing areas in which it may be deemed to have market power, subject to a restriction that such power will not be collusively re-sold back into such balancing areas. However, restrictions exist on sales by LG&E of power at market-based rates in the LG&E and KU and Big Rivers Electric Corporation balancing areas. In June 2007, the FERC issued Order No. 697 implementing certain reforms to market-based rate regulations, including restrictions similar to those previously in place for the Company's power sales at balancing area interfaces. In December 2008, the FERC issued Order No. 697-B potentially placing additional restrictions on certain power sales involving areas where market power is deemed to exist. As a condition of receiving and retaining market-based rate authority, LG&E must comply with applicable affiliate restrictions set forth in the FERC regulation. During September 2008, the Company submitted a regular triennial update filing under market-based rate regulations.

In June 2009, the FERC issued Order No. 697-C which generally clarified certain interpretations relating to power sales and purchases at balancing area interfaces or into balancing areas involving market power. In July 2009, the FERC issued an Order approving the Company's September 2008 application for market-based rate authority. During July 2009, affiliates of LG&E completed a

transaction terminating certain prior generation and power marketing activities in the Big Rivers Electric Corporation balancing area, which termination should ultimately allow a filing to request a determination that the Company no longer is deemed to have market power in such balancing area.

LG&E conducts certain of its wholesale power sales activities in accordance with existing market-based rate authority principles and interpretations. Future FERC proceedings relating to Orders 697 or market-based rate authority could alter the amount of sales made at market-based versus cost-based rates. The Company's sales under market-based rate authority totaled $21 million for the year ended December 31, 2010.

As a result of the EPAct 2005, certain formerly voluntary reliability standards became mandatory in June 2007 and authority was delegated to various Regional Reliability Organizations ("RROs") by the NERC, which was authorized by the FERC to enforce compliance with such standards, including promulgating new standards. Failure to comply with mandatory reliability standards can subject a registered entity to sanctions, including potential fines of up to $1 million per day, as well as non-monetary penalties, depending upon the circumstances of the violation. The Utilities are members of SERC, which acts as LG&E's and KU's RRO. During December 2009 and April, July and August 2010, the Utilities submitted ten self-reports relating to various standards, which self-reports remain in the early stages of RRO review and therefore, the Utilities are unable to estimate the outcome of these matters. Mandatory reliability standard settlements commonly also include non-penalty elements, including compliance steps and mitigation plans. Settlements with the SERC proceed to NERC and FERC review before becoming final. While the Utilities believe they are in compliance with the mandatory reliability standards, events of potential non-compliance may be identified from time-to-time. The Utilities cannot predict such potential violations or the outcome of self-reports described above.

In April 2010, the Kentucky Commission commenced a proceeding to investigate natural gas retail competition programs; their regulatory, financial and operational aspects and potential benefits, if any, of such programs to Kentucky consumers. A number of entities, including LG&E, were parties to the proceeding. In December 2010, the Kentucky Commission issued an Order in the proceeding declining to endorse natural gas competition at the retail level, noting the existence of a number of transition or oversight costs and an uncertain level of economic benefits in such programs. With respect to existing natural gas transportation programs available to large commercial or industrial users, the Order indicates that the Kentucky Commission will review utilities' current tariff structures, user thresholds and other terms and conditions of such programs, as part of such utilities' next regular natural gas rate cases.

Integrated resource planning ("IRP") regulations in Kentucky require major utilities to make triennial IRP filings with the Kentucky Commission. In April 2008, LG&E and KU filed their 2008 joint IRP with the Kentucky Commission. The IRP provides historical and projected demand, resource and financial data and other operating performance and system information. The Kentucky Commission issued a staff report and Order closing this proceeding in December 2009. LG&E expects to file their next IRP in April 2011.

PPL, LG&E's ultimate parent, is a holding company under PUHCA 2005. PPL, its utility subsidiaries, including LG&E and certain of its non-utility subsidiaries, are subject to extensive regulation by the FERC with respect to numerous matters, including electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties, payments of dividends out of capital and surplus, financial matters and inter-system sales of non-power goods and services. LG&E believes that it has adequate authority, including financing authority, under existing FERC Orders and regulations to conduct its business and will seek additional authorization when necessary.

The EPAct 2005 was enacted in August 2005. Among other matters, this comprehensive legislation contains provisions mandating improved electric reliability standards and performance; granting enhanced civil penalty authority to the FERC; providing economic and other incentives relating to transmission, pollution control and renewable generation assets; increasing funding for clean coal generation incentives; repealing the Public Utility Holding Company Act of 1935; enacting PUHCA 2005; and expanding FERC jurisdiction over public utility holding companies and related matters via the Federal Power Act and PUHCA 2005.

In February 2006, the Kentucky Commission initiated an administrative proceeding to consider the requirements of the EPAct 2005, Subtitle E Section 1252, Smart Metering, which concerns time-based metering and demand response and Section 1254, Interconnections. EPAct 2005 requires each state regulatory authority to conduct a formal investigation and issue a decision on whether or not it is appropriate to implement certain Section 1252 standards within eighteen months after the enactment of EPAct 2005 and to commence consideration of Section 1254 standards within one year after the enactment of EPAct 2005. Following a public hearing with all Kentucky jurisdictional electric utilities, in December 2006, the Kentucky Commission issued an Order in this proceeding indicating that the EPAct 2005 Section 1252 and Section 1254 standards should not be adopted. However, all five Kentucky Commission jurisdictional utilities were required to file real-time pricing pilot programs for their large commercial and industrial customers. LG&E developed a real-time pricing pilot program for large industrial and commercial customers and filed the details of the plan with the Kentucky Commission in April 2007. In February 2008, the Kentucky Commission issued an Order approving the real-time pricing pilot program proposed by LG&E for implementation within approximately eight months. The tariff was filed in October 2008, with an effective date of December 1, 2008. LG&E files annual reports on the program within 90 days of each plan year end for the three-year pilot period.

Pursuant to an LG&E 2004 rate case settlement agreement and as referred to in the Kentucky Commission EPAct 2005 Administrative Order, LG&E made its responsive pricing and smart metering pilot program filing, which addresses real-time pricing for residential and general service customers, in March 2007. In July 2007, the Kentucky Commission approved the application as filed, for 100 residential customers and a sampling of other customers and authorized LG&E to establish the responsive pricing and smart metering pilot program, recovery of non-specific customer costs through the DSM billing mechanism and the filing of annual reports by April 1, 2009, 2010 and 2011. LG&E must also file an evaluation of the program by July 1, 2011.

In October 2005, LG&E received from the FERC a new license to upgrade, operate and maintain the Ohio Falls Hydroelectric Project. The license is for a period of 40 years, effective November 2005. LG&E began refurbishing the facility to add approximately 20 Mw of generating capacity in 2004 and plans to spend approximately $89 million from 2011 to 2014.

In February 2007, LG&E and KU filed a Joint Application and Testimony for Proposed Green Energy Riders. In May 2007, a Kentucky Commission Order was issued authorizing LG&E to establish Small and Large Green Energy Riders, allowing customers to contribute funds to be used for the purchase of renewable energy credits. During November 2009, LG&E and KU filed an application to both continue and modify the existing Green Energy Programs. In February 2010, the Kentucky Commission approved the Utilities' application, as filed.

In July 2007, LG&E filed an application with the Kentucky Commission for the establishment of a Home Energy Assistance program. During September 2007, the Kentucky Commission approved the five-year program as filed, effective in October 2007. The programs were scheduled to terminate in September 2012 and is funded through a $0.10 per month meter charge. Effective February 6, 2009, as a result of the settlement agreement in the 2008 base rate case, the program is funded through a $0.15 per month meter charge. As a condition in the settlement in the change of control proceeding before the Kentucky Commission in the PPL acquisition, the program was extended to September 2015.

As part of its base rate case filed on July 29, 2008, LG&E proposed to change the due date for customer bill payments from 15 days to 10 days to align its collection cycle with KU. In addition, in its rate case filed on July 29, 2008, KU proposed to include a late payment charge if payment is not received within 15 days from the bill issuance date to align with LG&E. The settlement agreements approved in the rate cases in February 2009 changed the due date for customer bill payments to 12 days after bill issuance for both LG&E and KU.

In December 2007, LG&E filed a depreciation study with the Kentucky Commission as required by a previous Order. In August 2008, the Kentucky Commission issued an Order consolidating the

depreciation study with the base rate case proceeding. The approved settlement agreement in the rate case established new depreciation rates effective February 2009.

In March 2008, LG&E received Kentucky Commission approval for a Brownfield Development Rider, which offers a discounted rate to electric customers who meet certain usage and location requirements, including taking new service at a Brownfield site, as certified by the appropriate Kentucky state agency. The rider permits special contracts with such customers which provide for a series of declining partial rate discounts over an initial five-year period of a longer service arrangement. The tariff is intended to promote local economic redevelopment and efficient usage of utility resources by aiding potential reuse of vacant Brownfield sites.

In May 2008, the Kentucky Commission on its own motion initiated a proceeding to establish interconnection and net metering guidelines in accordance with amendments to existing statutory requirements for net metering of electricity. The jurisdictional electric utilities and intervenors in this case presented proposed interconnection guidelines to the Kentucky Commission in October 2008. In a January 2009 Order, the Kentucky Commission issued the Interconnection and Net Metering Guidelines—Kentucky that were developed by all parties to the proceeding. LG&E does not expect any financial or other impact as a result of this Order. In April 2009, LG&E filed revised net metering tariffs and application forms pursuant to the Kentucky Commission's Order. The Kentucky Commission issued an Order in April 2009, which suspended for five months all net metering tariffs filed by the jurisdictional electric utilities. This suspension was intended to allow sufficient time for review of the filed tariffs by the Kentucky Commission Staff and intervening parties.

In June 2009, the Kentucky Commission Staff held an informal conference with the parties to discuss issues related to the net metering tariffs filed by LG&E. Following this conference, the intervenors and LG&E resolved all issues and LG&E filed revised net metering tariffs with the Kentucky Commission. In August 2009, the Kentucky Commission issued an Order approving the revised tariffs.

In November 2008, the Kentucky Commission initiated an administrative proceeding to consider new standards as a result of the Energy Independence and Security Act of 2007 ("EISA 2007"), part of which amends the Public Utility Regulatory Policies Act of 1978 ("PURPA"). There are four new PURPA standards and one non-PURPA standard applicable to electric utilities. The proceeding also considers two new PURPA standards applicable to natural gas utilities. EISA 2007 requires state regulatory commissions and non-regulated utilities to begin consideration of the rate design and smart grid investments no later than December 19, 2008 and to complete the consideration by December 19, 2009. The Kentucky Commission established a procedural schedule that allowed for data discovery and testimony through July 2009. In October 2009, the Kentucky Commission held an informal conference for the purpose of discussing issues related to the standard regarding the consideration of Smart Grid investments. A public hearing has not been scheduled in this matter.

A summary of LG&E's net ARO assets, ARO liabilities and regulatory assets established under the asset retirement and environmental obligations guidance of the FASB ASC follows:

	ARO Net Assets			ARO Liabilities			Regulatory Assets

As of December 31, 2008, Predecessor	$	4		$	(31	)	$	29
ARO accretion and depreciation		(1	)		(2	)		3
ARO settlements		—			1			(2	)
Removal cost incurred		—			1			—

As of December 31, 2009, Predecessor		3			(31	)		30
ARO accretion and depreciation		—			(2	)		2
Reclassification for retired assets		(1	)		—			1
ARO revaluation—change in estimates		29			(30	)		1
Removal cost incurred		—			1			—

As of October 31, 2010, Predecessor		31			(62	)		34
ARO accretion and depreciation		(1	)		—			1
Purchase accounting—fair value adjustment		15			13			(28	)

As of December 31, 2010, Successor	$	45		$	(49	)	$	7

In September 2010, the Company performed a revaluation of its AROs as a result of recently proposed environmental legislation and improved ability to forecast asset retirement costs due to recent construction and retirement activity.

In November 2010, the Company recorded a purchase accounting adjustment to fair value AROs due to the PPL acquisition.

Pursuant to regulatory treatment prescribed under the regulated operations guidance of the FASB ASC, an offsetting regulatory credit was recorded in "Depreciation and amortization" in the Statements of Income for the Successor of $1 million in 2010 and $2 million for the Predecessor for the ARO accretion and depreciation expense. The offsetting regulatory credit recorded was $2 million in 2009 and 2008 for the ARO accretion and depreciation expense. The ARO liabilities are offset by cash settlements that have not yet been applied. Therefore, ARO net assets, ARO liabilities and regulatory assets balances do not net to zero.

LG&E's AROs are primarily related to the final retirement of assets associated with generating units and natural gas mains and wells. LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property.

Therefore, under the asset retirement and environmental obligations guidance of the FASB ASC, no material asset retirement obligations are recorded for transmission and distribution assets.

debt, floating rate debt and interest rate swaps. At December 31, 2010, LG&E's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was less than $1 million.

LG&E uses over-the-counter interest rate swaps to limit exposure to market fluctuations in interest expense. Pursuant to Company policy, use of these derivative instruments is intended to mitigate risk, earnings and cash flow volatility and is not speculative in nature.

LG&E's interest rate swap agreements range in maturity through 2033, with aggregate notional amounts of $179 million as of December 31, 2010 and December 31, 2009. Under these swap agreements, LG&E paid fixed rates averaging 4.52% and received variable rates based on LIBOR or the Securities Industry and Financial Markets Association's municipal swap index averaging 0.23% and 0.20% at December 31, 2010 and December 31, 2009, respectively. Beginning in the third quarter of 2010, the unrealized gains and losses on the interest rate swaps are included in a regulatory asset based on an Order from the Kentucky Commission in the 2010 rate case, whereby the cost of a terminated swap was allowed to be recovered in base rates.

The fair value of the interest rate swaps is determined by a quote from the counterparty. This value is verified monthly by the Company using a model that calculates the present value of future payments under the swap utilizing current swap market rates obtained from another dealer active in the swap market and validated by market transactions. Market liquidity is considered; however, the valuation does not require an adjustment for market liquidity as the market is very active for the type of swaps used by the Company. LG&E considered the impact of its own credit risk and that of counterparties by evaluating credit ratings and financial information and adjusting market valuations to reflect such credit risk. LG&E and all counterparties had strong investment grade ratings at December 31, 2010. In addition, the Company and certain counterparties have agreed to post margin if the credit exposure exceeds certain thresholds. Cash collateral related to interest rate swaps at December 31, 2010 and December 31, 2009 was $19 million and $17 million, respectively. Cash collateral for interest rate swaps is classified as a long-term "Other asset" on the accompanying Balance Sheets.

The table below shows the fair value and Balance Sheets location of interest rate swap derivatives:

The interest rate swaps are accounted for on a fair value basis in accordance with the derivatives and hedging guidance of the FASB ASC. The tables below show the pre-tax amount and income statement location of derivative gains and losses for the change in the mark-to-market value of the interest rate swaps, realized losses and the change in the ineffective portion of the interest rate swaps deemed highly effective, during the periods ended December 31, 2010, October 31, 2010, December 31, 2009 and December 31, 2008, including the impact of reclassifying these amounts to regulatory assets during the period ended October 31, 2010. For the period ended October 31, 2010, LG&E recorded a pre-tax gain of less than $1 million in interest expense to reflect the change in the ineffective portion of the interest rate swaps deemed highly effective and recorded pre-tax gains of $21 million and $9 million, respectively, to reflect the reclassification of the ineffective swaps and the terminated swap to a regulatory asset:



		Successor		Predecessor
							Year Ended December 31,
		November 1, 2010 through December 31, 2010		January 1, 2010 through October 31, 2010			Year Ended December 31,
Gain (Loss) Recognized in Income	Location	November 1, 2010 through December 31, 2010		January 1, 2010 through October 31, 2010			2009			2008
Change in the ineffective portion deemed highly effective	Interest expense	$	—	$	—		$	1		$	(8	)
Reclassification to regulatory assets of unrealized gain on interest rate swaps	Derivative gain (loss)		—		21			—			—
Unrealized gain (loss) on ineffective swaps	Derivative gain (loss)		—		(10	)		21			(35	)
Reclassification to regulatory assets of unrealized gain on terminated swap	Derivative gain (loss)		—		9			—
Realized loss on swaps	Derivative gain(loss)		—		(1	)		(3	)		(2	)

		$	—	$	19		$	19		$	(45	)

No gain or loss on hedging interest rate swaps was recognized in other comprehensive income for the periods ended December 31, 2010 and October 31, 2010. The gain on interest rate swaps recognized in other comprehensive income for the year ended December 31, 2009 was $5 million, and the loss on interest rate swaps recognized in other comprehensive income for the year ended December 31, 2008, was $8 million. For the period ended October 31, 2010, the gain on derivatives reclassified from "Accumulated other comprehensive income" to "Regulatory assets" was $23 million.

Prior to including the unrealized gains and losses on the interest rate swaps in regulatory assets, amounts previously recorded in accumulated other comprehensive income were reclassified into earnings in the same period during which the derivative forecasted transaction affected earnings. No amount was amortized from accumulated other comprehensive income to income in the period ended December 31, 2010, and in the periods ended October 31, 2010, December 31, 2009 and December 31, 2008, amortization was less than $1 million each year.

A decline of 100 basis points in the current market interest rates would reduce the fair value of LG&E's interest rate swaps by $28 million.

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns. Energy trading activities are principally forward financial transactions to manage price risk and are accounted for as non-hedging derivatives on a mark-to-market basis in accordance with the derivatives and hedging guidance of the FASB ASC.

Energy trading and risk management contracts are valued using prices based on active trades from Intercontinental Exchange Inc. In the absence of a traded price, midpoints of the best bids and offers are the primary determinants of valuation. When sufficient trading activity is unavailable, other inputs include prices quoted by brokers or observable inputs other than quoted prices, such as one-sided bids or offers as of the balance sheet date. Quotes are verified quarterly using an independent pricing source of actual transactions. Quotes for combined off-peak and weekend timeframes are allocated between the two timeframes based on their historical proportional ratios to the integrated cost. No other adjustments are made to the forward prices. No changes to valuation techniques for energy trading and risk management activities occurred during 2010 or 2009. Changes in market pricing, interest rate and volatility assumptions were made during both years.

The table below shows the fair value and balance sheet location of energy trading and risk management derivative contracts:

Assets and liabilities from long-term energy trading and risk management derivative contracts total less than $1 million at December 31, 2010 and were zero at December 31, 2009.

commitments were with counterparties rated BBB-/Baa3 equivalent or better. The Company has reserved against counterparty credit risk based on LG&E's own creditworthiness (for net liabilities) and its counterparty's creditworthiness (for net assets). The Company applies historical default rates within varying credit ratings over time provided by S&P or Moody's. At December 31, 2010 and December 31, 2009, counterparty credit reserves related to energy trading and risk management contracts were zero and less than $1 million respectively.

The net volume of electricity based financial derivatives outstanding at December 31, 2010 and December 31, 2009, was 869,101 Mwh and 315,600 Mwh, respectively. Cash collateral related to the energy trading and risk management contracts was $3 million and $2 million at December 31, 2010 and December 31, 2009, respectively. Cash collateral related to the energy trading and risk management contracts is recorded in "Prepayments and other current assets" on the Balance Sheets.

The following table presents the effect of market-traded forward contract derivatives not designated as hedging instruments on income:

Certain of LG&E's derivative contracts contain credit contingent provisions which would permit the counterparties with which LG&E is in a net liability position to require the transfer of additional collateral upon a decrease in LG&E's credit rating. Some of these provisions would require LG&E to transfer additional collateral or permit the counterparty to terminate the contract if LG&E's credit rating were to fall below investment grade. Some of these provisions also allow the counterparty to require additional collateral upon each decrease in the credit rating at levels that remain above investment grade. In either case, if LG&E's credit rating were to fall below investment grade (i.e., below BBB- for S&P or Baa3 for Moody's) and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent provisions require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization by LG&E on derivative instruments in net liability positions.

Additionally, certain of LG&E's derivative contracts contain credit contingent provisions that require LG&E to provide "adequate assurance" of performance if the other party has reasonable grounds for insecurity regarding LG&E's performance of its obligation under the contract. A counterparty demanding adequate assurance could require a transfer of additional collateral or other

security, including letters of credit, cash and guarantees from a creditworthy entity. A demand for additional assurance would typically involve negotiations among the parties. However, amounts disclosed below represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" provisions.

To determine net liability positions, LG&E uses the fair value of each agreement. The aggregate fair value of all derivative instruments with the credit contingent provisions described above that were in a net liability position at December 31, 2010 was $25 million of which LG&E had posted collateral of $19 million in the normal course of business. At December 31, 2010, if the credit contingent provisions underlying these derivative instruments were triggered due to a credit downgrade below investment grade, LG&E would have been required to post an additional $6 million of collateral to its counterparties.

LG&E adopted the fair value guidance in the FASB ASC in two phases. Effective January 1, 2008, the Company adopted it for all financial instruments and non-financial instruments accounted for at fair value on a recurring basis, and effective January 1, 2009, the Company adopted it for all non-financial instruments accounted for at fair value on a non-recurring basis. The FASB ASC guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. As a basis for considering such assumptions, the FASB ASC guidance establishes a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value.

The carrying values and estimated fair values of LG&E's non-trading financial instruments follow:

The long-term fixed rate pollution control bond valuations reflect prices quoted by investment banks, which are active in the market for these instruments. First mortgage bond valuations reflect prices quoted from a third party service. The fair value of the long-term debt due to affiliated company is determined using an internal valuation model that discounts the future cash flows of each loan at current market rates as determined based on quotes from investment banks that are actively involved in capital markets for utilities and factor in LG&E's credit ratings and default risk. The fair values of the interest rate swaps reflect price quotes from investment banks, consistent with the fair value measurements and disclosures guidance of the FASB ASC. This value is verified monthly by the Company using a model that calculates the present value of future payments under the swap utilizing current swap market rates obtained from another dealer active in the swap market and validated by market transactions. The fair values of cash and cash equivalents, accounts receivable, accounts payable and notes payable are substantially the same as their carrying values.

LG&E has classified the applicable financial assets and liabilities that are accounted for at fair value into the three levels of the fair value hierarchy, as discussed in Note 1, Summary of Significant Accounting Policies.

The Company classifies its derivative cash collateral balances within level 1 based on the funds being held in a demand deposit account. The Company classifies its derivative energy trading and risk management contracts and interest rate swaps within level 2 because it values them using prices actively quoted for proposed or executed transactions, quoted by brokers or observable inputs other than quoted prices.

The following tables set forth, by level within the fair value hierarchy, LG&E's financial assets and liabilities that were accounted for at fair value on a recurring basis.

December 31, 2010		Level 1		Level 2		Level 3		Total

Financial assets:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Short-term investments—municipal debt securities		163		—		—		163
	Energy trading and risk management contracts		3		—		—		3
	Restricted cash		19		—		—		19

Total financial assets		$	187	$	—	$	—	$	187

Financial liabilities:
	Energy trading and risk management contracts	$	—	$	2	$	—	$	2
	Interest rate swaps		—		34		—		34

Total financial liabilities		$	—	$	36	$	—	$	36

December 31, 2009		Level 1		Level 2		Level 3		Total

Financial assets:
	Energy trading and risk management contract cash collateral	$	2	$	—	$	—	$	2
	Energy trading and risk management contracts		—		2		—		2
	Interest rate swap cash collateral		17		—		—		17

Total financial assets		$	19	$	2	$	—	$	21

Financial liabilities:
	Energy trading and risk management contracts	$	—	$	2	$	—	$	2
	Interest rate swaps		—		28		—		28

Total financial liabilities		$	—	$	30	$	—	$	30

There were no level 3 measurements for the periods ending December 31, 2010 and December 31, 2009.

In connection with PPL's acquisition of LKE and its subsidiaries, goodwill was recorded on November 1, 2010. In addition, as of November 1, 2010, certain intangible assets were adjusted to their fair value and new intangible assets were recorded. See Note 2, Acquisition by PPL, for further information.

The Company performs its required annual goodwill impairment test in the fourth quarter. Impairment tests are performed between the annual tests when the Company determines that a triggering event has occurred that would, more likely than not, reduce the fair value of a reporting unit below its carrying value. The goodwill impairment test is comprised of a two-step process. In step 1, the Company identifies a potential impairment by comparing the estimated fair value of the regulated utilities (the goodwill reporting unit) to their carrying value, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the fair value is less than the carrying value, then step 2 is performed to measure the amount of impairment loss, if any. The step 2 calculation compares the implied fair value of the goodwill to the carrying value of the goodwill. The implied fair value of goodwill is equal to the excess of the company's estimated fair value over the fair values of its identified assets and liabilities. If the carrying value of goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess (but not in excess of the carrying value).

In connection with PPL's acquisition of LKE on November 1, 2010, LG&E recorded goodwill on November 1, 2010. The allocation of the goodwill to LG&E was based on the net asset value of the Company. The goodwill represents value paid for the rate regulated business located in a defined service area with a constructive regulatory environment, which provides for future investment, earnings and cash flow growth, as well as the talented and experienced workforce. LG&E's franchise values are being attributed to the going concern value of the business, and thus were recorded as goodwill rather than a separately identifiable intangible asset. None of the goodwill recognized is deductible for income tax purposes or included in customer rates. See Note 2, Acquisition by PPL, for further information.

For the 2010 annual impairment test, the primary valuation technique used was an income methodology based on management's estimates of forecasted cash flows for LG&E, with those cash flows discounted to present value using rates commensurate with the risks of those cash flows. Management also took into consideration the acquisition price paid by PPL. The discounted cash flows for LG&E were based on discrete financial forecasts developed by management for planning purposes and consistent with those given to PPL. Cash flows beyond the discrete forecasts were estimated using a terminal-value calculation, which incorporated historical and forecasted financial trends for LG&E. No impairment resulted from the fourth quarter test, as the determined fair value of LG&E was greater than its carrying value.

The gross carrying amount and the accumulated amortization of other intangible assets were as follows:

(a): The gross carrying amount represents the fair value of coal contracts recognized as a result of the 2010 acquisition by PPL. The weighted average amortization period of these contracts is three years. See Note 2, Acquisition by PPL, for further information.
(b): The gross carrying amount represents the fair value of land rights recognized as a result of adopting PPL's accounting policies in the Successor period. The weighted average amortization period of these rights is 10 years. See Note 1, Summary of Significant Accounting Policies, for further information.
(c): The gross carrying amount represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL, as well as the reclassification of amounts from inventory to intangible assets as a result of adopting PPL's accounting policies in the Successor period. The weighted average amortization period of these emission allowances is three years. See Note 2, Acquisition by PPL, for further information.
(d): The gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. The weighted average amortization period of the power purchase agreement is 8 years. See Note 2, Acquisition by PPL, for further information.

Current intangible assets and long-term intangible assets are included in "Other intangible assets" in their respective areas on the Balance Sheets in 2010. Intangible assets of LG&E resulting from purchasing accounting adjustments are not recoverable in rates.

Amortization expense, excluding consumption of emission allowances, was $7 million for the Successor in 2010. The estimated aggregate amortization expense for each of the next five years is as follows:

Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.

LG&E's customer receivables arise from deliveries of electricity and natural gas. Electric revenues represented 77%, 72% and 69% of LG&E's revenues for 2010, 2009 and 2008, respectively. Natural gas revenues represented 23%, 28% and 31% of LG&E's revenues for 2010, 2009 and 2008, respectively. During 2010, the Company's 10 largest electric and natural gas customers accounted for less than 11% and less than 14% of total volumes, respectively. Volumes associated with the ten largest natural gas customers were predominantly for transportation service.

Effective November 2008, LG&E and its employees represented by the IBEW Local 2100 entered into a three-year collective bargaining agreement. This agreement provides for negotiated increases or changes to wages, benefits or other provisions. The employees represented by this bargaining agreement comprise approximately 68% of the Company's workforce at December 31, 2010.

LG&E employees benefit from both funded and unfunded retirement benefit plans. Its defined benefit pension plans cover employees hired by December 31, 2005.Employees hired after this date participate in the Retirement Income Account ("RIA"), a defined contribution plan. The postretirement plan includes health care benefits that are contributory with participants' contributions adjusted annually. The Company uses December 31 as the measurement date for its plans.

The following tables provide a reconciliation of the changes in the defined benefit plans' obligations, the fair value of assets and the funded status of the plan for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor:



										Other Postretirement Benefits
	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	2010			2010			2009			2010			2010			2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	485		$	441		$	429		$	92		$	90		$	88
Service cost		1			3			4			—			1			1
Interest cost		4			21			26			1			4			5
Benefits paid, net of retiree contributions		(4	)		(22	)		(27	)		(1	)		(5	)		(6	)
Actuarial (gain) loss and other		(3	)		42			9			(1	)		2			2

Benefit obligation at end of period	$	483		$	485		$	441		$	91		$	92		$	90



										Other Postretirement Benefits
	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	2010			2010			2009			2010			2010			2009
Change in plan assets:
Fair value of plan assets at beginning of period	$	352		$	325		$	286		$	6		$	5		$	3
Actual return on plan assets		9			30			59			—			—			—
Employer contributions		—			20			8			1			6			8
Benefits paid, net of retiree contributions		(4	)		(22	)		(27	)		(1	)		(5	)		(6	)
Administrative expenses and other		—			(1	)		(1	)		—			—			—

Fair value of plan assets at end of period	$	357		$	352		$	325		$	6		$	6		$	5

Funded status at end of period	$	(126	)	$	(133	)	$	(116	)	$	(85	)	$	(86	)	$	(85	)

The following tables provide the amounts recognized in the Balance Sheets and information for plans with benefit obligations in excess of plan assets for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor:

Amounts recognized in regulatory assets and liabilities for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor consist of:

Additional information for plans with accumulated benefit obligations in excess of plan assets for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor consists of:

The amounts recognized in regulatory assets for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor:

For discussion of the pension and postretirement regulatory assets, see Note 3, Rates and Regulatory Matters.

The following tables provide the components of net periodic benefit cost for pension and other postretirement benefit plans. The tables include the costs associated with both LG&E employees and Servco employees, who provide services to LG&E. The Servco costs are allocated to LG&E based on employees' labor charges and are approximately 44%, 43% and 42% of Servco's costs for 2010, 2009 and 2008, respectively.

The estimated amounts that will be amortized from regulatory assets into net periodic benefit cost in 2011 are shown in the following table:

The weighted average assumptions used in the measurement of LG&E's pension and postretirement benefit obligations for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor are shown in the following table:

For the first ten months of 2010, the discount rates used to determine the pension and postretirement benefit obligations and the period expense were determined using the Mercer Pension Discount Yield Curve. This model takes the plans' cash flows and matches them to a yield curve that provides the equivalent yields on zero-coupon corporate bonds for each maturity. The discount rate is the single rate that produces the same present value of cash flows. The selection of the various discount rates represents the equivalent single rate under a broad-market AA yield curve constructed by Mercer.

For the last two months of 2010, the Towers Watson Yield Curve was used to determine the discount rate. This model starts with an analysis of the expected benefit payment stream for its plans. This information is first matched against a spot-rate yield curve. A portfolio of Aa-graded non-callable (or callable with make-whole provisions) bonds, with a total amount outstanding in excess of

$667 billion, serves as the base from which those with the lowest and highest yields are eliminated to develop the ultimate yield curve. The results of this analysis are considered together with other economic data and movements in various bond indices to determine the discount rate assumption.

The weighted average assumptions used in the measurement of LG&E's pension and postretirement net periodic benefit costs for November 1, 2010 through December 31, 2010, for the Successor, and for January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor are shown in the following table:

To develop the expected long-term rate of return on assets assumption, LG&E considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the current asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio. The Company has determined that the 2011 expected long-term rate of return on assets assumption should be 7.25%.

The following describes the effects on pension benefits by changing the major actuarial assumptions discussed above:

For measurement purposes, an 8% annual increase in the per capita cost of covered health care benefits was assumed for the first ten months of 2010. The rate was assumed to decrease gradually to 4.5% by 2029 and remain at that level thereafter. For the last two months of 2010, an 8% annual increase in the per capita cost of covered health care benefits was assumed, and the rate was assumed to decrease gradually to 5.5% by 2019. For 2011, a 9% annual increase in the per capita cost of covered health care benefits is assumed, and the rate is assumed to decrease gradually to 5.5% by 2019. This change in the length of the health care trend was made to conform to PPL's accounting policies.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have resulted in an increase or decrease of less than $1 million to the 2010 total of service and interest costs components and an increase or decrease of less than $2 million in year end 2010 postretirement benefit obligations.

The following list provides the amount of expected future benefit payments, which reflect expected future service cost:

The following table shows the pension plans' weighted average asset allocation by asset category at December 31:

The investment policy of the pension plans was developed in conjunction with financial and actuarial consultants, investment advisors and legal counsel. The goal of the investment policy is to preserve the capital of the pension plans' assets and maximize investment earnings in excess of inflation with acceptable levels of volatility. The return objective is to exceed the benchmark return for the policy index comprised of the following: Russell 3000 Index, MSCI-EAFE Index, Barclays Capital Aggregate and Barclays Capital U.S. Long Government/Credit Bond Index in proportions equal to the targeted asset allocation.

Evaluation of performance focuses on a long-term investment time horizon over rolling three and five year periods. The assets of the pension plans are broadly diversified within different asset classes (equities, fixed income securities and cash equivalents).

To minimize the risk of large losses in a single asset class, no more than 5% of the portfolio will be invested in the securities of any one issuer with the exclusion of the U.S. government and its agencies. The equity portion of the fund is diversified among the market's various subsections to

diversify risk, maximize returns and avoid undue exposure to any single economic sector, industry group or individual security. The equity subsectors include, but are not limited to, growth, value, small capitalization and international.

In addition, the overall fixed income portfolio may have an average weighted duration, or interest rate sensitivity which is within +/- 20% of the duration of the overall fixed income benchmark. Foreign bonds in the aggregate shall not exceed 10% of the total fund. The portfolio may include a limited investment of up to 20% in below investment grade securities provided that the overall average portfolio quality remains "AA" or better. The below investment grade securities include, but are not limited to, medium-term notes, corporate debt, non-dollar and emerging market debt and asset backed securities. The cash investments should be in securities that are either short maturities (not to exceed 180 days) or readily marketable with modest risk.

Derivative securities are permitted only to improve the portfolio's risk/return profile, to modify the portfolio's duration or to reduce transaction costs and must be used in conjunction with underlying physical assets in the portfolio. Derivative securities that involve speculation, leverage, interest rate anticipation, or any undue risk whatsoever are not deemed appropriate investments.

The investment objective for the postretirement benefit plan is to provide current income consistent with stability of principal and liquidity while maintaining a stable net asset value of $1.00 per share. The postretirement funds are invested in a prime cash money market fund that invests primarily in a portfolio of short-term, high-quality fixed income securities issued by banks, corporations and the U.S. government.

LG&E has classified plan assets that are accounted for at fair value into the three levels of the fair value hierarchy, as defined by the fair value measurements and disclosures guidance of the FASB ASC. See Note 6, Fair Value Measurements, for further information.

A financial instrument's level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

A description of the valuation methodologies used to measure plan assets at fair value is provided below:

The preceding methods described may produce a fair value that may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different

methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. There were no changes in the plans' valuation methodologies during 2010.

The following table sets forth, by level within the fair value hierarchy, the plans' assets at fair value at December 31:

There are no assets categorized as level 1 or level 3 as of December 31, 2010 and December 31, 2009.

LG&E made a discretionary contribution to the pension plan of $20 million in 2010 and $8 million in 2009. Servco made discretionary contributions to its pension plan of $9 million and $8 million in 2010 and 2009, respectively. The amount of future contributions to the pension plan will depend upon the actual return on plan assets and other factors, but the Company funds its pension obligations in a manner consistent with the Pension Protection Act of 2006. The Company made contributions totaling $64 million in January 2011. See Note 19, Subsequent Events, for further information.

The Company made contributions to its other postretirement benefit plan of $7 million in 2010 and 2009. In 2011, the Company anticipates making voluntary contributions to fund Voluntary Employee Beneficiary Association trusts to match the annual postretirement expense and funding the 401(h) plan up to the maximum amount allowed by law.

The Pension Protection Act of 2006 was enacted in August 2006. New rules regarding funding of defined benefit plans are generally effective for plan years beginning in 2008. Among other matters, this comprehensive legislation contains provisions applicable to defined benefit plans which generally (i) mandate full funding of current liabilities within seven years; (ii) increase tax-deduction levels regarding contributions; (iii) revise certain actuarial assumptions, such as mortality tables and discount rates; and (iv) raise federal insurance premiums and other fees for under-funded and distressed plans. The legislation also contains a number of provisions relating to defined-contribution plans and qualified and non-qualified executive pension plans and other matters. The Company's plans met the minimum funding requirements as defined by the Pension Protection Act of 2006 for years ended December 31, 2010 and 2009.

LG&E has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of the employees' contributions. The costs of this matching were $3 million in 2010, 2009 and 2008.

LG&E also makes contributions to RIAs within the thrift savings plans for certain employees not covered by the noncontributory defined benefit pension plans. These employees consist of those hired after December 31, 2005. The Company makes these contributions based on years of service and the employees' wage and salary levels, and makes them in addition to the matching contributions discussed above. The amounts contributed by the Company under this arrangement were less than $1 million in 2010, 2009 and 2008.

In March 2010, Health Care Reform (the Patient Protection and Affordable Care Act of 2010) was signed into law. Many provisions of Health Care Reform do not take effect for an extended period of time and many aspects of the law which are currently unclear or undefined will likely be clarified in future regulations.

The Company has evaluated these provisions of Health Care Reform on its benefit programs in consultation with its actuarial consultants and has determined that the excise tax will not have an impact on its postretirement medical plans. The requirement to extend dependent coverage up to age 26 is not expected to have a significant impact on active or retiree medical costs. The Company will continue to monitor the potential impact of any changes to the existing provisions and implementation guidance related to Health Care Reform on its benefit programs.

LG&E's federal income tax return is included in a United States consolidated income tax return filed by LKE's direct parent. Prior to October 31, 2010 the return was included in the consolidated return of E.ON US Investments Corp. Due to the acquisition by PPL, the return will be included in the consolidated PPL return beginning November 1, 2010, for each tax period. Each subsidiary of the consolidated tax group, including LG&E, calculates its separate income tax for each period. The resulting separate-return tax cost or benefit is paid to or received from the parent company or its designee. The Company also files income tax returns in various state jurisdictions. While 2007 and later years are open under the federal statute of limitations, Revenue Agent Reports for 2007-2008 have been received from the IRS, effectively closing these years to additional audit adjustments. Tax years beginning with 2007 were examined under an IRS program, Compliance Assurance Process ("CAP").

This program accelerates the IRS's review to begin during the year applicable to the return and ends 90 days after the return is filed. Adjustments for 2007, agreed to and recorded in January 2009, were comprised of $5 million of depreciable temporary differences. For 2008, the IRS allowed additional deductions in connection with the Company's application for a change in repair deductions and disallowed certain bonus depreciation claimed on the original return. The net temporary tax impact for the Company was a $13 million reduction in tax and was recorded in 2010. The 2009 federal return was filed in the third quarter of 2010 and the IRS issued a Partial Acceptance Letter in connection with CAP. The IRS is continuing to review bonus depreciation, storms and other repairs, contributions in aid of construction and purchased natural gas adjustments. No net adverse impact is expected from these remaining areas. The short tax year beginning January 1, 2010 through October 31, 2010, is also being examined under CAP. No material items have been raised by the IRS at this time. The two month period beginning November 1, 2010 and ending December 31, 2010 is not currently under examination.

Additions and reductions of uncertain tax positions during 2010, 2009 and 2008 were less than $1 million. Possible amounts of uncertain tax positions for LG&E that may decrease within the next 12 months total less than $1 million and are based on the expiration of the audit periods as defined in the statutes. If recognized, the less than $1 million of unrecognized tax benefits would reduce the effective income tax rate.

The amount LG&E recognized as interest expense and interest accrued related to unrecognized tax benefits was less than $1 million for the twelve month periods ended and as of December 31, 2010, 2009 and 2008. The interest expense and interest accrued is based on IRS and Kentucky Department of Revenue large corporate interest rates for underpayment of taxes. At the date of adoption, the Company accrued less than $1 million in interest expense on uncertain tax positions. LG&E records the interest as "Interest expense" and penalties, if any, as "Operating expenses" on the Statements of Income and "Other current liabilities" on the Balance Sheets, on a pre-tax basis. No penalties were accrued by the Company through December 31, 2010.



		Successor			Predecessor
								Year Ended December 31,
		November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			Year Ended December 31,
		November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			2009			2008
Current:
	Federal	$	(4	)	$	32		$	26		$	37
	State		1			5			4			4
Deferred:
	Federal—net		12			21			14			(2	)
	State—net		1			2			2			(2	)
Investment tax credit—deferred			—			—			4			8
Amortization of investment tax credit			—			(2	)		(3	)		(4	)

Total income tax expense		$	10		$	58		$	47		$	41

In June 2006, LG&E and KU filed a joint application with the U.S. Department of Energy ("DOE") requesting certification to be eligible for an investment tax credit applicable to the

construction of TC2. In November 2006, the DOE and the IRS announced that LG&E and KU were selected to receive the tax credit. A final IRS certification required to obtain the investment tax credit was received in August 2007. In September 2007, LG&E received an Order from the Kentucky Commission approving the accounting of the investment tax credit, which includes a full depreciation basis adjustment for the amount of the credit. LG&E's portion of the TC2 tax credit is approximately $24 million. Based on eligible construction expenditures incurred, LG&E recorded an investment tax credit of $4 million and $8 million in 2009 and 2008, respectively, decreasing current federal income taxes. As of December 31, 2009, LG&E had recorded its maximum credit of $24 million. The income tax expense impact from amortizing this credit over the life of the related property began when the facility was placed in service in January 2011.

In March 2008, certain environmental and preservation groups filed suit in federal court in North Carolina against the DOE and IRS claiming the investment tax credit program was in violation of certain environmental laws and demanded relief, including suspension or termination of the program. The plaintiffs voluntarily dismissed their complaint in August 2010.

Components of deferred income taxes included in the Balance Sheets are shown below:



			Successor			Predecessor
			December 31, 2010			December 31, 2009
Deferred income tax liabilities:
	Depreciation and other plant-related items		$	423		$	383
	Regulatory assets and other			121			45
	Pension and related benefits			16			2

		Total deferred income tax liabilities		560			430

Deferred income tax assets:
	Regulatory liabilities and other			86			—
	Investment tax credit			8			11
	Income taxes due to customers			13			16
	Liabilities and other			36			34

		Total deferred income tax assets		143			61

		Net deferred income tax liabilities	$	417		$	369

Balance sheet classification:
	Prepayments and other current assets		$	(2	)	$	(4	)
	Deferred income taxes (non-current)			419			373

		Net deferred income tax liabilities	$	417		$	369

The Company expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.

A reconciliation of differences between the income tax expense at the statutory U.S. federal income tax rate and LG&E's actual income tax expense follows:



		Successor			Predecessor
								Year Ended December 31,
		November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			Year Ended December 31,
		November 1, 2010 through December 31, 2010			January 1, 2010 through October 31, 2010			2009			2008
Statutory federal income tax expense		$	10		$	58		$	50		$	46
State income taxes—net of federal benefit			1			4			4			1
Qualified production activities deduction			—			(2	)		(1	)		(1	)
Amortization of investment tax credits			(1	)		(2	)		(3	)		(4	)
Other differences—net			—			—			(3	)		(1	)

	Income tax expense	$	10		$	58		$	47		$	41

Effective income tax rate			34.5	%		34.7	%		33.1	%		31.3	%

The Tax Relief, Unemployment Reauthorization and Job Creation Act of 2010, enacted December 17, 2010 provided, among other provisions, certain incentives related to bonus depreciation and 100% expensing of qualifying capital expenditures. LG&E benefited from these new provisions by reducing its 2010 current federal income tax expense. This reduction in federal taxable income for LG&E does, however, result in a reduction of LG&E's Section 199 Manufacturing deduction, which is based on manufacturing taxable income and correspondingly increases income tax expense. The impact from these changes on 2010 was not material; however, LG&E anticipates a significant reduction of taxable income in 2011 and 2012 and a corresponding loss of most, if not all, of the Section 199 Manufacturing deduction for the following two years.

As summarized below, at December 31, 2010, long-term debt consisted of first mortgage bonds and secured pollution control bonds. At December 31, 2009, long-term debt and the current portion of long-term debt consisted primarily of pollution control bonds and long-term loans from affiliated companies.



		Successor			Predecessor
		2010			2009
Long-term debt to affiliated companies		$	—		$	485
Secured first mortgage bonds, net of debt discount and amortization of debt discount			535			—
Pollution control revenue bonds, collateralized by first mortgage bonds			574			411
Fair value adjustment from purchase accounting			7			—
Unamortized discount			(4	)		—

	Total long-term debt		1,112			896
Less current portion			—			120

	Long-term debt, excluding current portion	$	1,112		$	776

As of December 31, 2009, long-term debt includes $120 million of pollution control bonds that were classified as current portion because these bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events. These bonds include Jefferson County 2001 Series A and B and Trimble County 2001 Series A and B. Maturity dates for these bonds range from 2026 to 2027. As of December 31, 2009, the bonds were classified as current portion of long-term debt because investors could put the bonds back to the Company within one year. As of December 31, 2010, the bonds were reclassified as long-term debt. See Note 1, Summary of Significant Accounting Policies, for changes in classification.

Pollution control bonds are obligations of LG&E issued in connection with tax-exempt pollution control bonds by various counties in Kentucky. A loan agreement obligates the Company to make debt service payments to the counties in amounts equal to the debt service due from the counties on the related pollution control bonds. Depending on the type of expense, the Successor capitalized debt expenses in long-term other regulatory assets or long-term other assets to align with the term of the debt to which the expenses were related. The Predecessor capitalized debt expenses in current or long-term other regulatory assets or other current or long-term other assets based on the amount of expense expected to be recovered within the next year through rate recovery. Both Predecessor and Successor amortized debt expenses over the lives of the related bond issues. The Predecessor presentation and the Successor presentation are both appropriate under regulatory practices and GAAP.

In October 2010, in order to secure their respective obligations with respect to the pollution control bonds, LG&E issued first mortgage bonds to the pollution control bond trustees. LG&E's first mortgage bonds contain terms and conditions that are substantially parallel to the terms and conditions of the counties' debt, but provide that obligations are deemed satisfied to the extent of payments under the related loan agreement, and thus generally require no separate payment of principal and interest except under certain circumstances, including should LG&E default on the respective loan agreement. Also in October 2010, one national rating agency revised downward the short-term credit rating of the pollution control bonds and the Company's issuer rating as a result of the pending acquisition by PPL.

Several series of LG&E's pollution control bonds are insured by monoline bond insurers whose ratings have been reduced due to exposures relating to insurance of sub-prime mortgages. At December 31, 2010, LG&E had an aggregate $574 million (including $163 million of reacquired bonds) of outstanding pollution control indebtedness, of which $135 million is in the form of insured auction rate securities wherein interest rates are reset either weekly or every 35 days via an auction process. Beginning in late 2007, the interest rates on these insured bonds began to increase due to investor

concerns about the creditworthiness of the bond insurers. Since 2008, interest rates increased and the Company experienced "failed auctions" when there were insufficient bids for the bonds. When a failed auction occurs, the interest rate is set pursuant to a formula stipulated in the indenture.

The instruments governing these auction rate bonds permit LG&E to convert the bonds to other interest rate modes, such as various short-term variable rates, long-term fixed rates or intermediate-term fixed rates that are reset infrequently.

As of December 31, 2010, LG&E continued to hold repurchased bonds in the amount of $163 million. As of December 31, 2009, the repurchased bonds were reported net by excluding from long-term debt. As of December 31, 2010, the accounting treatment changed and the repurchased bonds were reported gross by including in long-term debt). See Note 1, Summary of Significant Accounting Policies, for changes in classification. See Note 19, Subsequent Events, and Note 18, Available for Sale Debt Securities, for details regarding the remarketing of the repurchased bonds on January 13, 2011.

As a result of downgrades of the monoline insurers by all of the rating agencies to levels below that of the Company's rating, the debt ratings of the Company's insured bonds are all based on the Company's senior secured debt rating and are not influenced by the monoline bond insurer ratings.

Interest rate swaps are used to hedge certain underlying variable-rate debt obligations. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on the pollution control bonds. As of December 31, 2010 and 2009, the Company had swaps with an aggregate notional value of $179 million. Beginning in the third quarter of 2010, the unrealized gains and losses of the interest rate swaps are included in a regulatory asset, which offsets the long-term derivative liabilities. See Note 5, Derivative Financial Instruments, for further information.

In connection with the PPL acquisition, on November 1, 2010, LG&E borrowed $485 million from a PPL subsidiary, in order to repay loans from a subsidiary of E.ON. LG&E used the net proceeds received from the sale of the first mortgage bonds to repay the debt owed to the PPL subsidiary arising from the borrowing.

In November 2010, LG&E issued first mortgage bonds totaling $535 million and used the proceeds to repay the loans from a PPL subsidiary mentioned above and for general corporate purposes. The first mortgage bonds were issued at a discount as described in the table below:

The first mortgage bonds were issued by LG&E in accordance with the rules of Section 144A of the Securities Act of 1933. LG&E has entered into a registration rights agreement in which it has agreed to file a registration statement with the SEC relating to an offer to exchange the first mortgage bonds for publicly tradable securities having substantially identical terms. If ultimate registration and/or certain milestones are not completed by certain dates in mid- and late 2011, the Company has agreed to pay liquidated damages to the bondholders. The liquidated damages would total 0.25% per annum of the principal amount of the bonds for the first 90 days and 0.50% per annum of the principal amount thereafter until the conditions described above have been cured.

There were no redemptions or maturities of long-term debt for 2009. Redemptions and maturities of long-term debt for 2010 are summarized below:

There were no issuances of long-term debt in 2009. Issuances of long-term debt for 2010 are summarized below:

As of December 31, 2010, all of the Company's long-term debt is secured by a first mortgage lien on substantially all of the real and tangible personal property of the Company located in Kentucky.

See Note 1, Summary of Significant Accounting Policies, for certain debt refinancing and associated transactions completed by LG&E in connection with the PPL acquisition, Note 2, Acquisition by PPL, for the adjustment made to the pollution control bonds to reflect fair value and Note 15, Related Party Transactions, for long-term debt payable to affiliates.

LG&E participates in an intercompany money pool agreement wherein LKE and/or KU make funds available to LG&E at market-based rates (based on highly rated commercial paper issues) of up to $400 million. Details of the balances are as follows:

LKE maintains revolving credit facilities totaling $300 million at December 31, 2010 and $313 million at December 31, 2009, to ensure funding availability for the money pool. At December 31, 2010, the LKE facility is with PPL Investment Corp. LKE pays PPL Investment Corp. an annual commitment fee based on the Utilities' current bond ratings on the unused portion of the commitment. At December 31, 2009, one facility, totaling $150 million, was with E.ON North America, Inc., while the remaining line, totaling $163 million, was with Fidelia, both affiliated companies of E.ON. The balances are as follows:

As of December 31, 2010, the Company maintained a $400 million revolving line of credit with a group of banks maturing in December 2014. The revolving line of credit allows LG&E to issue letters of credit or borrow funds up to $400 million. Outstanding letters of credit reduce the facility's available

borrowing capacity. The Company pays the banks an annual commitment fee based on current bond ratings on the unused portion of the commitment. At December 31, 2010, there was $163 million borrowed under this facility with an average interest rate of 2.27%. This credit agreement contains financial covenants requiring the borrower's debt to total capitalization ratio to not exceed 70%, as calculated pursuant to the credit agreement, and other customary covenants.

As of December 31, 2009, the Company maintained bilateral lines of credit with unaffiliated financial institutions totaling $125 million, maturing in June 2012. The Company paid the banks an annual commitment fee on the unused portion of the commitment. At December 31, 2009, there was no balance outstanding under any of these facilities. These facilities were terminated on November 1, 2010 in conjunction with the PPL acquisition.

See Note 1, Summary of Significant Accounting Policies, for certain debt refinancing and associated transactions completed by LG&E in connection with the PPL acquisition and Note 15, Related Party Transactions, for long-term debt payable to affiliates.

LG&E leases office space, office equipment, plant equipment, real estate, railcars, telecommunications and vehicles and accounts for these leases as operating leases. Total lease expense less amounts contributed by affiliated companies occupying a portion of the office space leased by the Company, was $6 million each for 2010, 2009 and 2008. The future minimum annual lease payments for operating leases for years subsequent to December 31, 2010, are shown in the following table:

The Company is a participant in a sale and leaseback transaction involving its 38% interest in two jointly owned CTs at KU's E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. The Utilities have provided funds to fully defease the lease and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if the Utilities had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals. At December 31, 2010, the Balance Sheets included these assets at a value of $39 million, which is reflected in "Regulated utility plant, —electric and natural gas."

In case of default under the lease, the Company is obligated to pay to the lessor its share of certain fees or amounts. Primary events of default include loss or destruction of the CTs, failure to insure or maintain the CTs and unwinding of the transaction due to governmental actions. No events of default currently exist with respect to the lease. Upon any termination of the lease, whether by default or expiration of its term, title to the CTs reverts jointly to LG&E and KU.

At December 31, 2010, the maximum aggregate amount of default fees or amounts was $7 million, of which LG&E would be responsible for 38% (approximately $3 million). The Company has made arrangements with LKE, via guarantee and regulatory commitment, for LKE to pay its full portion of any default fees or amounts.

LG&E has provided letters of credit as of December 31, 2010 and 2009, for off-balance sheet obligations totaling $3 million to support certain obligations related to landfill reclamation and letters of credit for off-balance sheet obligations totaling less than $1 million to support certain obligations related to workers' compensation.

LG&E has a contract for power purchases with OVEC, terminating in 2026, for various Mw capacities. LG&E holds a 5.63% investment interest in OVEC with 10 other electric utilities. LG&E is not the primary beneficiary; therefore, the investment is not consolidated into the Company's financial statements, but is recorded on the cost basis. OVEC is located in Piketon, Ohio, and owns and operates two coal-fired power plants, Kyger Creek Station in Ohio, and Clifty Creek Station in Indiana. LG&E is contractually entitled to 5.63% of OVEC's output, approximately 134 Mw of nameplate generation capacity. Pursuant to the OVEC power purchase contract, the Company may be conditionally responsible for a 5.63% pro-rata share of certain obligations of OVEC under defined circumstances. These contingent liabilities may include unpaid OVEC indebtedness as well as shortfall amounts in certain excess decommissioning costs and postretirement benefits other than pension. LG&E's contingent potential proportionate share of OVEC's December 31, 2010 outstanding debt was $78 million. Future obligations for power purchases from OVEC are demand payments, comprised of annual minimum debt service payments, as well as contractually required reimbursement of plant operating, maintenance and other expenses and are shown in the following table:

LG&E has contracts to purchase coal, natural gas and natural gas transportation. Future obligations are shown in the following table:

LG&E had approximately $128 million of commitments in connection with its construction program at December 31, 2010.

In June 2006, LG&E 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, LG&E 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, LG&E 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 Company took care, custody and control of TC2 on January 22, 2011, and has dispatched the unit to meet customer demand since that date. LG&E and the contractor agreed to a further amendment of the construction agreement whereby the contractor will complete certain actions relating to identifying and completing any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages. LG&E cannot currently estimate the ultimate outcome of these matters.

remaining claims with the exception of two additional deficiencies which the KDAQ was directed to address. The EPA determined that the proposed permit subsequently issued by the KDAQ satisfied the conditions of the EPA Order although the agency recommended certain enhancements to the administrative record. In January 2010, the KDAQ issued a final permit revision incorporating the proposed changes to address the EPA objections. In March 2010, the Sierra Club submitted a petition to the EPA to object to the permit revision, which is now pending before the EPA. The Company believes that the final permit as revised should not have a material adverse effect on its financial condition or results of operations. However, until the EPA issues a final ruling on the pending petition and all applicable appeals have been exhausted, the Company cannot predict the final outcome of this matter.

The Company's operations are subject to a number of environmental laws and regulations governing, among other things, air emissions, wastewater discharges, the use, handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee health and safety. As indicated below and summarized at the conclusion of this section, evolving environmental regulations will likely increase the level of capital and operating and maintenance expenditures incurred by the Company during the next several years. Based upon prior regulatory precedent, the Company believes that many costs of complying with such pending or future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but the Company can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

The Clean Air Act requires the EPA to periodically review the available scientific data for six criteria pollutants and establish concentration levels in the ambient air sufficient to protect the public health and welfare with an extra margin for safety. These concentration levels are known as NAAQS. Each state must identify "nonattainment areas" within its boundaries that fail to comply with the NAAQS and develop a SIP to bring such nonattainment areas into compliance. If a state fails to develop an adequate plan, the EPA must develop and implement a plan. As the EPA increases the stringency of the NAAQS through its periodic reviews, the attainment status of various areas may change, thereby triggering additional emission reduction obligations under revised SIPs aimed to achieve attainment.

In 1997, the EPA established new NAAQS for ozone and fine particulates that required additional reductions in SO₂ and NOx emissions from power plants. In 1998, the EPA issued its final "NOx SIP Call" rule requiring reductions in NOx emissions of approximately 85% from 1990 levels in order to mitigate ozone transport from the midwestern U.S. to the northeastern U.S. To implement the new federal requirements, Kentucky amended its SIP in 2002 to require electric generating units to reduce their NOx emissions to 0.15 pounds weight per MMBtu on a company-wide basis. In 2005, the EPA issued the CAIR which required additional SO₂ emission reductions of 70% and NOx emission reductions of 65% from 2003 levels. The CAIR provided for a two-phase cap and trade program, with initial reductions of NOx and SO₂ emissions due by 2009 and 2010, respectively, and final reductions due by 2015. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAIR.

In July 2008, a federal appeals court issued a ruling finding deficiencies in the CAIR and vacating it. In December 2008, the Court amended its previous Order directing the EPA to promulgate a new regulation but leaving the CAIR in place in the interim. The remand of the CAIR results in some uncertainty with respect to certain other EPA or state programs and proceedings and the Utilities' compliance plans relating thereto due to the interconnection of the CAIR with such associated programs.

In January 2010, the EPA proposed a revised NAAQS for ozone which would increase the stringency of the standard. In addition, the EPA published final revised NAAQS standards for NO₂ and SO₂ in February 2010 and June 2010, respectively, which are more stringent than previous standards. Depending on the level of action determined necessary to bring local nonattainment areas into compliance with the revised NAAQS standards, LG&E's power plants are potentially subject to requirements for additional reductions in SO₂ and NOx emissions.

In July 2010, the EPA issued the proposed CATR, which serves to replace the CAIR. The CATR provides for a two-phase SO₂ reduction program with Phase I reductions due by 2012 and Phase II reductions due by 2014. The CATR provides for NOx reductions in 2012, but the EPA advised that it is studying whether additional NOx reductions should be required for 2014. The CATR is more stringent than the CAIR as it accelerates certain compliance dates and provides for only intrastate and limited interstate trading of emission allowances. In addition to its preferred approach, the EPA is seeking comment on an alternative approach which would provide for individual emission limits at each power plant. The EPA has announced that it will propose additional "transport" rules to address compliance with revised NAAQS standards for ozone and particulate matter which will be issued by the EPA in the future, as discussed below.

As provided in the Clean Air Act, the EPA investigated hazardous air pollutant emissions from electric utilities and submitted a report to Congress identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the EPA issued the CAMR establishing mercury standards for new power plants and requiring all states to issue new SIPs including mercury requirements for existing power plants. The EPA issued a model rule which provides for a two-phase cap and trade program with initial reductions due by 2010 and final reductions due by 2018. The CAMR provided for reductions of 70% from 2003 levels. The EPA closely integrated the CAMR and CAIR programs to ensure that the 2010 mercury reduction targets would be achieved as a "co-benefit" of the controls installed for purposes of compliance with the CAIR. In addition, in 2006, the Metro Louisville Air Pollution Control District adopted rules aimed at regulating additional hazardous air pollutants from sources including power plants.

In February 2008, a federal appellate court issued a decision vacating the CAMR. The EPA has entered into a consent decree requiring it to promulgate a utility Maximum Achievable Control Technology rule to replace the CAMR with a proposed rule due by March 2011 and a final rule by November 2011. Depending on the final outcome of the rulemaking, the CAMR could be replaced by new rules with different or more stringent requirements for reduction of mercury and other hazardous air pollutants. Kentucky has also repealed its corresponding state mercury regulations.

The Clean Air Act imposed a two-phased cap and trade program to reduce SO₂ emissions from power plants that were thought to contribute to "acid rain" conditions in the northeastern U.S. The Clean Air Act also contains requirements for power plants to reduce NOx emissions through the use of available combustion controls.

The Clean Air Act also includes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing future impairment and remedying any existing impairment of visibility in those areas. In 2005, the EPA issued its Clean Air Visibility Rule detailing how the Clean Air Act's BART requirements will be applied to facilities, including power plants built between 1962 and 1974 that emit certain levels of visibility impairing pollutants. Under the final rule, as the CAIR provided for more visibility improvement than BART, states are allowed to substitute CAIR requirements in their regional haze SIPs in lieu of controls that would otherwise be required by BART. The final rule has been challenged in the courts. Additionally, because the regional haze SIPs incorporate certain CAIR requirements, the remand of the CAIR could potentially impact regional haze SIPs. See "Ambient Air Quality" above for a discussion of CAIR-related uncertainties.

Many of the programs under the Clean Air Act utilize cap and trade mechanisms that require a company to hold sufficient emissions allowances to cover its authorized emissions on a company-wide basis and do not require installation of pollution controls on every generating unit. Under cap and trade programs, companies are free to focus their pollution control efforts on plants where such controls are particularly efficient and utilize the resulting emission allowances for smaller plants where such controls are not cost effective. LG&E had previously installed FGD equipment on all of its generating units prior to the effective date of the acid rain program. LG&E's strategy for its Phase II SO₂ requirements, which commenced in 2000, is to use accumulated emission allowances to defer certain additional capital expenditures and continue to evaluate improvements to further reduce SO₂ emissions. LG&E believes its costs in reducing SO₂, NOx and mercury emissions to be comparable to those of similarly situated utilities with like generation assets. LG&E's compliance plans are subject to many factors including developments in the emission allowance and fuels markets, future legislative and regulatory enactments, legal proceedings and advances in clean air technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner. LG&E expects to incur additional capital expenditures currently approved in its ECR plans totaling approximately $100 million during the 2011 through 2013 time period to achieve emissions reductions and manage coal combustion residuals. Monthly recovery is subject to periodic review by the Kentucky Commission.

level. As discussed below, legislation mandating GHG reductions has been introduced in the Congress, but no federal legislation has been enacted to date. In the absence of a program at the federal level, various states have adopted their own GHG emission reduction programs, including 11 northeastern U.S. states and the District of Columbia under the Regional GHG Initiative program and California. Substantial efforts to pass federal GHG legislation are on-going. The current administration has announced its support for the adoption of mandatory GHG reduction requirements at the federal level. The United States and other countries met in Copenhagen, Denmark, in December 2009, in an effort to negotiate a GHG reduction treaty to succeed the Kyoto Protocol, which is set to expire in 2013. In Copenhagen, the U.S. made a nonbinding commitment to, among other things, seek to reduce GHG emissions to 17% below 2005 levels by 2020 and provide financial support to developing countries. The United States and other nations met in Cancun, Mexico, in December 2010 to continue negotiations toward a binding agreement.

LG&E is monitoring on-going efforts to enact GHG reduction requirements and requirements governing carbon sequestration at the state and federal level and is assessing potential impacts of such programs and strategies to mitigate those impacts. In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, which was a comprehensive energy bill containing the first-ever nation-wide GHG cap and trade program. The bill provided for reductions in GHG emissions of 3% below 2005 levels by 2012, 17% by 2020 and 83% by 2050. In order to cushion potential rate impacts for utility customers, approximately 43% of emissions allowances would have initially been allocated at no cost to the electric utility sector, with this allocation gradually declining to 7% in 2029 and zero thereafter. The bill would have also established a renewable electricity standard requiring utilities to meet 20% of their electricity demand through renewable energy and energy efficiency by 2020. The bill contained additional provisions regarding carbon capture and sequestration, clean transportation, smart grid advancement, nuclear and advanced technologies and energy efficiency.

In September 2009, the Clean Energy Jobs and American Power Act, which was largely patterned on the House legislation, was introduced in the U.S. Senate. The Senate bill raised the emissions reduction target for 2020 to 20% below 2005 levels and did not include a renewable electricity standard. While the initial bill lacked detailed provisions for the allocation of emissions allowances, a subsequent revision incorporated allowance allocation provisions similar to the House bill. Although Senators Kerry and Lieberman and others worked to reach a consensus on GHG legislation, no bill passed the Senate in 2010. The Company is closely monitoring the progress of pending energy legislation, but the prospect for passage of comprehensive GHG legislation in 2011 is uncertain.

equivalent to at least 75,000 tons of carbon dioxide to obtain permits under the Prevention of Significant Deterioration Program. Such new or modified facilities would be required to install Best Available Control Technology. While the Company is unaware of any currently available GHG control technology that might be required for installation on new or modified power plants, it is currently assessing the potential impact of the rule. The final rule will apply to new and modified power plants beginning in January 2011. The Company is unable to predict whether mandatory GHG reduction requirements will ultimately be enacted through legislation or regulations. In December 2010, the EPA announced that it plans to promulgate GHG New Source Performance Standards for power plants, including both new and existing facilities. A proposed rule is expected by July 2011, while a final rule is expected by May 2012. In the absence of either a proposed or final regulation, LG&E is unable to assess the potential impact of any future regulation.

A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting facilities. In October 2009, a three-judge panel of the United States Court of Appeals for the 5^th Circuit in the case of Comer v. Murphy Oil reversed a lower court, holding that private plaintiffs have standing to assert certain common law claims against more than 30 utility, oil, coal and chemical companies. In March 2010, the court vacated the opinion of the three-judge panel and granted a motion for rehearing but subsequently denied the appeal due to the lack of a quorum. The appellate ruling leaves in effect the lower court ruling dismissing the plaintiffs' claims. In January 2011, the Supreme Court denied petitioner's petition for review, which effectively brings the case to an end. The Comer complaint alleged that GHG emissions from the defendants' facilities contributed to global warming which increased the intensity of Hurricane Katrina. E.ON, the former indirect parent of the Utilities, was named as a defendant in the complaint but was not a party to the proceedings due to the failure of the plaintiffs to pursue service under the applicable international procedures. LG&E continues to monitor relevant GHG litigation to identify judicial developments that may be potentially relevant to operations.

The EPA has undertaken various initiatives in response to the December 2008 impoundment failure at the TVA's Kingston power plant, which resulted in a major release of coal combustion byproducts into the environment. The EPA issued information requests to utilities throughout the country, including LG&E, to obtain information on their ash ponds and other impoundments. In addition, the EPA inspected a large number of impoundments located at power plants to determine their structural integrity. The inspections included several of LG&E's impoundments, which the EPA found to be in satisfactory condition except for certain impoundments at the Mill Creek and Cane Run stations, which were determined to be in fair condition. In June 2010, the EPA published proposed regulations for coal combustion byproducts handled in landfills and ash ponds. The EPA has proposed two alternatives: (1) regulation of coal combustion byproducts in landfills and ash ponds as a hazardous waste or (2) regulation of coal combustion byproducts as a solid waste with minimum national standards. Under both alternatives, the EPA has proposed safety requirements to address the structural integrity of ash ponds. In addition, the EPA will consider potential refinements of the provisions for beneficial reuse of coal combustion byproducts.

The EPA has also announced plans to develop revised effluent limitation guidelines governing discharges from power plants and standards for cooling water intake structures. The EPA has further announced plans to develop revised standards governing the use of polychlorinated biphenyls ("PCB") in electrical equipment. The Company is monitoring these ongoing regulatory developments but will be unable to determine the impact until such time as new rules are finalized.

As a company with significant coal-fired generating assets, LG&E will likely be substantially impacted by pending or future environmental rules or legislation requiring mandatory reductions in GHG emissions or other air emissions, imposing more stringent standards on discharges to waterways, or establishing additional requirements for handling or disposal of coal combustion byproducts. These evolving environmental regulations will likely require an increased level of capital expenditures and increased incremental operating and maintenance costs by the Company over the next several years. Due to the uncertain nature of the final regulations that will ultimately be adopted by the EPA, including the reduction targets and the deadlines that will be applicable, the Company cannot finalize estimates of the potential compliance costs, but should the final rules incorporate additional emission reduction requirements, require more stringent emissions controls or implement more stringent byproducts storage and disposal practices, such costs will likely be significant. With respect to NAAQS, CATR, CAMR replacement and coal combustion byproducts developments, based upon a preliminary analysis of proposed regulations, the Company may be required to consider actions such as upgrading existing emissions controls, installing additional emissions controls, upgrading byproducts disposal and storage and possible early replacement of coal-fired units. Capital expenditures for LG&E associated with such actions are preliminarily estimated to be in the $1.5 to $1.8 billion range over the next ten years, although final costs may substantially vary. With respect to potential developments in water discharge, revised PCB standards or GHG initiatives, costs in such areas cannot be estimated due to the preliminary status or uncertain outcome of such developments, but would be in addition to the above amount and could be substantial. Ultimately, the precise impact on the Company's operations of these various environmental developments cannot be determined prior to the finalization of such requirements. Based upon prior regulatory precedent, the Company believes that many costs of complying with such pending or future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but the Company can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

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 generating station. In October 2010, the hearing officer issued a report and recommended Order providing for dismissal of the claims raised by the petitioners. In December 2010, the Secretary issued a final Order dismissing all claims and upholding the permit which petitioners subsequently appealed to Trimble County Circuit Court.

From time to time, LG&E appears before the EPA, various state or local regulatory agencies and state and federal courts regarding matters involving compliance with applicable environmental laws and regulations. Such matters include a prior Section 114 information request from the EPA relating to new source review issues at LG&E's Mill Creek Unit 4 and TC1; remediation obligations or activities for former manufactured gas plant sites or elevated PCB levels at existing properties; liability under the Comprehensive Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; and on-going claims regarding alleged particulate emissions from the Company's Cane Run generating station and claims regarding GHG emissions from the Company's generating stations. With respect to the former manufactured gas plant sites, LG&E has estimated that it could incur additional costs of less than $1 million for remaining clean-up activities under existing approved plans or agreements. Based on analysis to date, the resolution of these matters is not expected to have a material impact on the Company's operations.

The Company owns a 75% undivided interest in TC1 which the Kentucky Commission has allowed to be reflected in customer rates. Of the remaining 25% of the unit, IMEA owns a 12.12% undivided interest and IMPA owns a 12.88% undivided interest. Each company is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses and incremental assets.

The following data represent shares of the jointly owned property (capacity based on nameplate rating):

TC2 is a jointly owned unit at the Trimble County site. LG&E and KU own undivided 14.25% and 60.75% interests, respectively. Of the remaining 25%, IMEA owns a 12.12% undivided interest and IMPA owns a 12.88% undivided interest. Each company is responsible for its proportionate share of capital cost during construction and fuel, operation and maintenance cost when TC2 is in-service. With limited exceptions the Company took care, custody and control of TC2 on January 22, 2011, and has dispatched the unit to meet customer demand since that date. LG&E and the contractor agreed to a further amendment of the construction agreement whereby the contractor will complete certain actions

relating to identifying and completing any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages.In December 2009 and June 2008, LG&E sold assets to KU related to the construction of TC2 with a net book value of $48 million and $10 million, respectively.

		TC2

		LG&E			KU			IMPA			IMEA			Total
Ownership interest			14.25	%		60.75	%		12.88	%		12.12	%		100	%
Mw capacity			119			509			108			102			838
LG&E's 14.25% ownership:
	Plant held for future use	$	2
	Construction work in progress		187
	Accumulated depreciation		—

Net book value		$	189

KU's 60.75% ownership:
	Plant held for future use	$	62
	Construction work in progress		703
	Accumulated depreciation		(1	)

Net book value		$	764

LG&E and KU jointly own the following CTs and related equipment (capacity based on net summer capability) as of December 31, 2010:

Both LG&E's and KU's participating share of direct expenses of the jointly owned plants is included in the corresponding operating expenses on each company's respective Statements of Income, (i.e., fuel, maintenance of plant, other operating expense).

LG&E and subsidiaries of LKE and PPL engage in related party transactions. Transactions between LG&E and LKE subsidiaries are eliminated on consolidation of LKE. Transactions between LG&E and PPL subsidiaries are eliminated on consolidation of PPL. These transactions are generally performed at cost and are in accordance with FERC regulations under PUHCA 2005 and the applicable Kentucky Commission regulations.

LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load. When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E. When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU. These transactions are recorded as intercompany wholesale sales and purchases are recorded by each company at a price equal to the seller's fuel cost. Savings realized from purchasing electricity intercompany instead of generating from their own higher costs units or purchasing from the market are shared equally between the Utilities. The volume of energy each company has to sell to the other is dependent on its native load needs and its available generation.

These sales and purchases are included in the Statements of Income as "Operating revenues", "Power purchased" expenses and "Other operation and maintenance expenses". LG&E's intercompany electric revenues and power purchased expenses were as follows:

See Note 11, Long-Term Debt, and Note 12, Notes Payable and Other Short-Term Obligations, for details of intercompany borrowing arrangements. Intercompany agreements do not require interest payments for receivables related to services provided when settled within 30 days.

Interest paid to LKE on the money pool arrangement was less than $1 million for 2010 and 2009.

In March and September 2010, the Company paid dividends of $30 million and $25 million, respectively, to its sole shareholder, LKE. The Company also paid dividends of $80 million and $40 million to LKE in 2009 and 2008, respectively.

The Company received no capital contributions in 2010 or 2009, but received a capital contribution of $20 million from its sole shareholder, LKE, in December 2008.

In 2010, LG&E sold and bought assets of less than $1 million to and from KU. In December 2009, LG&E sold assets to KU related to the construction of TC2 with a net book value of $48 million.

Servco provides the Company with a variety of centralized administrative, management and support services. Associated charges include payroll taxes paid by Servco on behalf of LG&E, labor and burdens of Servco employees performing services for LG&E, coal purchases and other vouchers paid by Servco on behalf of LG&E. The cost of these services is directly charged to the Company, or for general costs which cannot be directly attributed, charged based on predetermined allocation factors, including the following ratios: number of customers, total assets, revenues, number of employees and/or other statistical information. These costs are charged on an actual cost basis.

In addition, the Utilities provide services to each other and to Servco. Billings between the Utilities relate to labor and overheads associated with union and hourly employees performing work for the other utility, charges related to jointly-owned generating units and other miscellaneous charges. Billings from LG&E to Servco include cash received by Servco on behalf of LG&E, tax settlements and other payments made by the Company on behalf of other non-regulated businesses which are reimbursed through Servco.

	Pre-Tax Accumulated Derivative Gain (Loss)			Income Taxes			Net

Balance at December 31, 2007, Predecessor	$	(20	)	$	8		$	(12	)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments		(2	)		—			(2	)

Balance at December 31, 2008, Predecessor	$	(22	)	$	8		$	(14	)

Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments		5			(1	)		4

Balance at December 31, 2009, Predecessor	$	(17	)	$	7		$	(10	)

Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments		17			(7	)		10

Balance at October 31, 2010, Predecessor	$	—		$	—		$	—

Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments		—			—			—

Balance at December 31, 2010, Successor	$	—		$	—		$	—

LG&E's available for sale debt securities include the following pollution control bonds, which were repurchased from the remarketing agent in 2008:

In January 2011, LG&E remarketed these bonds to unaffiliated investors. See Note 19, Subsequent Events, for further discussion regarding the remarketing of these bonds.

Subsequent events have been evaluated through February 25, 2011, the date of issuance of these statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

With limited exceptions the Company took care, custody and control of TC2 on January 22, 2011, and has dispatched the unit to meet customer demand since that date. LG&E and KU and the contractor agreed to a further amendment of the construction agreement whereby the contractor will complete certain actions relating to identifying and completing any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages.

On January 13, 2011, LG&E remarketed the Louisville/Jefferson County Metro Government 2003 Series A and 2007 Series B bonds, having $128 million and $35 million in outstanding principal amount, respectively, which bonds had been previously repurchased by LG&E and shown in "Available for sale debt securities" on the Balance Sheets. In connection with the remarketing, each bond series was converted to a mode wherein the interest rate is fixed for an intermediate term but not the full term of the bond. The bonds will bear interest at the rate of 1.90% each, until April 2012 and June 2012, in the case of the 2003 Series A and 2007 Series B bonds, respectively. At the end of the intermediate term, the Company must remarket the bonds or buy them back. As of January 13, 2011, LG&E had no remaining repurchased bonds. LG&E used the proceeds from the remarketed bonds to repay the balance of its credit facility.

As of March 31, 2011 and December 31, 2010
and for the three months ended
March 31, 2011 and 2010


ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
BART		Best Available Retrofit Technology
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CATR		Clean Air Transport Rule
CCN		Certificate of Public Convenience and Necessity
Clean Air Act		The Clean Air Act, as amended in 1990
Company		Louisville Gas and Electric Company
DSM		Demand Side Management
ECR		Environmental Cost Recovery
EPA		U.S. Environmental Protection Agency
EPAct 2005		Energy Policy Act of 2005
FAC		Fuel Adjustment Clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		Flue Gas Desulfurization
GAAP		U.S. Generally Accepted Accounting Principles
GHG		Greenhouse Gas
GSC		Gas Supply Clause
IRP		Integrated Resource Plan
KDAQ		Kentucky Division for Air Quality
Kentucky Commission		Kentucky Public Service Commission
KU		Kentucky Utilities Company
LG&E		Louisville Gas and Electric Company
LKE		LG&E and KU Energy LLC and Subsidiaries
MISO		Midwest Independent Transmission System Operator
Moody's		Moody's Investor Services, Inc.
Mwh		Megawatt hours
NAAQS		National Ambient Air Quality Standards
NO₂		Nitrogen Dioxide
NOx		Nitrogen Oxide
OVEC		Ohio Valley Electric Corporation
PBR		Performance Based Rates
PCB		Polychlorinated Biphenyls
PPL		PPL Corporation
Predecessor		The Company during the time period prior to November 1, 2010
S&P		Standard & Poor's Rating Service
SEC		U.S. Securities and Exchange Commission
Servco		LG&E and KU Services Company
SIP		State Implementation Plan
SO₂		Sulfur Dioxide
Successor		The Company during the time period after October 31, 2010
TC2		Trimble County Unit 2
Utilities		LG&E and KU

Louisville Gas and Electric Company
Condensed Financial Statements
(Unaudited)
As of March 31, 2011 and December 31, 2010
and for the three months ended
March 31, 2011 and 2010

Louisville Gas and Electric Company

Condensed Statements of Income

(unaudited)

($ millions)

			Successor			Predecessor

			Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
Operating revenues:
	Retail and wholesale		$	371		$	342
	Wholesale to affiliate (Note 10)			27			24

Total operating revenues				398			366
Operating expenses:
	Fuel for electric generation			85			83
	Power purchased			10			10
	Power purchased from affiliate (Note 10)			11			7
	Natural gas supply			89			81
	Other operation and maintenance			94			87
	Depreciation and amortization			36			34

Total operating expenses				325			302

Operating income				73			64
Interest expense				11			4
Interest expense to affiliate				—			7
Other income (expense)—net				(1	)		(2	)

Income from continuing operations, before income taxes				61			51
Income taxes (Note 7)				22			18

		Net income	$	39		$	33

The accompanying notes are an integral part of these condensed financial statements.

Louisville Gas and Electric Company

Condensed Statements of Comprehensive Income

(unaudited)

($ millions)

The accompanying notes are an integral part of these condensed financial statements.

Louisville Gas and Electric Company

Condensed Statements of Common Equity

(unaudited)

($ millions)

The accompanying notes are an integral part of these condensed financial statements.

			March 31, 2011		December 31, 2010

Assets
Current assets:
	Cash and cash equivalents		$	28	$	2
	Accounts receivable (less allowance for doubtful accounts 2011, $3; 2010, $2):
		Customer		72		70
		Affiliate		24		30
		Other		4		13
	Unbilled revenues			58		81
	Fuel, materials and supplies:
		Fuel (predominantly coal)		68		68
		Natural gas stored underground		19		60
		Other materials and supplies		35		34
	Regulatory assets (Note 3)			14		13
	Available for sale debt securities (Note 10)			—		163
	Other intangible assets			27		36
	Prepayments and other current assets			16		13

Total current assets				365		583

Property, plant and equipment:
	Regulated utility plant			2,832		2,600
	Less: accumulated depreciation			44		17
	Construction work in progress			181		385

		Property, plant and equipment—net		2,969		2,968

Deferred debits and other noncurrent assets:
	Regulatory assets (Note 3):
		Pension and postretirement benefits		213		213
		Other regulatory assets		149		154
	Goodwill			389		389
	Other intangible assets			177		181
	Other long-term assets			31		31

Total deferred debits and other noncurrent assets				959		968

Total assets			$	4,293	$	4,519

The accompanying notes are an integral part of these condensed financial statements.

			March 31, 2011		December 31, 2010

Liabilities and Equity
Current liabilities:
	Notes payable to affiliate (Note 10)		$	—	$	12
	Note payable (Note 8)			—		163
	Accounts payable			83		100
	Accounts payable to affiliate (Note 10)			15		20
	Customer deposits			23		23
	Accrued taxes			18		10
	Regulatory liabilities (Note 3)			38		51
	Other current liabilities			41		38

Total current liabilities				218		417

Long-term bonds (Note 8)				1,112		1,112

Deferred credits and other noncurrent liabilities:
	Deferred income taxes			434		419
	Accumulated provision for pensions			67		126
	Investment tax credits			45		46
	Asset retirement obligations			49		49
	Regulatory liabilities:
		Accumulated cost of removal of utility plant (Note 3)		279		275
		Other regulatory liabilities (Note 3)		204		208
	Derivative liabilities (Note 4)			29		32
	Other long-term liabilities			113		114

Total deferred credits and other noncurrent liabilities				1,220		1,269

Equity:
	Common stock, without par value—authorized 75,000,000 shares, outstanding 21,294,223 shares			424		424
	Additional paid-in capital			1,278		1,278
	Retained earnings			41		19

Total equity				1,743		1,721

Commitments and contingent liabilities (Note 9)				—		—

Total liabilities and equity			$	4,293	$	4,519

The accompanying notes are an integral part of these condensed financial statements.

Louisville Gas and Electric Company

Condensed Statements of Cash Flows

(unaudited)

($ millions)

		Successor			Predecessor

		Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
Cash flows from operating activities:
Net income		$	39		$	33
Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation and amortization		36			34
	Deferred income taxes—net		13			3
	Provision for pension and postretirement benefits		8			7
	Other—net		2			(2	)
Change in current assets and liabilities:
	Accounts receivable		9			(18	)
	Unbilled revenues		23			16
	Fuel, materials and supplies		40			27
	Regulatory assets		(1	)		—
	Natural gas supply clause receivable—net		—			(26	)
	Prepayments and other current assets		(2	)		—
	Accounts payable		(14	)		8
	Accounts payable to affiliate		(5	)		3
	Accrued taxes		8			2
	Regulatory liabilities		(4	)		—
	Other current liabilities		3			(10	)
Pension and postretirement benefits funding			(65	)		(21	)
Other—net			3			4

Net cash provided by operating activities			93			60

Cash flows from investing activities:
	Construction expenditures		(35	)		(31	)
	Proceeds from sale of assets to affiliate		—			48
	Sales of marketable debt securities		163			—
	Change in restricted cash		(2	)		—

Net cash provided by investing activities		$	126		$	17

Cash flows from financing activities:
	Repayments of short-term note payable	$	(163	)	$	—
	Debt issuance costs		(1	)		—
	Changes in notes payable to affiliate—net		(12	)		(47	)
	Payment of dividends (Note 10)		(17	)		(30	)

Net cash used in financing activities			(193	)		(77	)

Change in cash and cash equivalents			26			—
Cash and cash equivalents at beginning of period			2			5

Cash and cash equivalents at end of period		$	28		$	5

The accompanying notes are an integral part of these condensed financial statements.

The accompanying condensed financial statements and notes should be read in conjunction with LG&E's Financial Statements and Additional Information Report for 2010.

Terms and abbreviations are explained in the index of abbreviations. Dollars are in millions unless otherwise noted.

The accompanying unaudited condensed financial statements have been prepared in accordance with GAAP for interim financial information and do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation in accordance with GAAP are reflected in the condensed financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed. The Condensed Balance Sheet at December 31, 2010, is derived from the 2010 audited Balance Sheet.

The results of operations for the three months ended March 31, 2011, are not necessarily indicative of the results to be expected for the full year ending December 31, 2011, or other future periods, because results for interim periods can be disproportionately influenced by various factors, developments and seasonal variations.

LG&E became an indirect wholly owned subsidiary of PPL when PPL acquired all of the outstanding limited liability company interests in the Company's direct parent, LKE, from E.ON US Investments Corp. on November 1, 2010.

LG&E's condensed financial statements and accompanying footnotes have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Predecessor activity covers the time period prior to November 1, 2010. Successor activity covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL accounting policies, which are discussed in the Company's Financial Statements and Additional Information Report for 2010. The cost basis of certain assets and liabilities were changed as of November 1, 2010, as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor period are not comparable to the Predecessor period.

Despite the separate presentation, the core operations of the Company have not changed. See Note 2, Acquisition by PPL, and Note 7, Goodwill and Intangible Assets, in the Company's Financial Statements and Additional Information Report for 2010 for information regarding the acquisition and the purchase accounting adjustments.

The following accounting policy disclosures represent updates to Note 1, Summary of Significant Accounting Policies, in LG&E's Financial Statements and Additional Information Report for 2010 and should be read in conjunction with that discussion.

LG&E's cost method investment, included in Other long-term assets on the Condensed Balance Sheets, consists of the LG&E's 5.63% investment in OVEC. LG&E and 11 other electric utilities are owners of OVEC, which is located in Piketon, Ohio. At March 31, 2011 and December 31, 2010, LG&E's investment in OVEC was not significant. LG&E is not the primary beneficiary of OVEC; therefore, it is not consolidated into the Company's financial statements and is accounted for under the cost method of accounting.

For a description of each line item of regulatory assets and liabilities and for descriptions of certain matters which may not have undergone material changes relating to the period covered by this quarterly report, reference is made to Note 3, Rates and Regulatory Matters, in LG&E's Financial Statements and Additional Information Report for 2010.

The Company is subject to the jurisdiction of the FERC and the Kentucky Commission in virtually all matters related to electric and natural gas utility regulation and as such, its accounting is subject to the regulated operations guidance of the FASB ASC. Given its position in the marketplace and the status of regulation in Kentucky, there are no plans or intentions to discontinue the application of the regulated operations guidance of the FASB ASC.

LG&E's base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain regulatory adjustments to exclude non-regulated investments and environmental compliance plans recovered separately through the ECR mechanism. At the time base rates were determined, no recorded regulatory assets or regulatory liabilities were excluded from the return on capitalization utilized in the calculation of base rates. Therefore, a return is earned on all regulatory assets existing at the time base rates were determined, except where such regulatory assets were offset by associated liabilities and thus, have no net impact on capitalization.

As a result of purchase accounting, certain fair value amounts, reflecting contracts that have favorable or unfavorable terms relative to market (e.g., coal, purchased power, emission allowances), were recorded on the Condensed Balance Sheets with offsetting regulatory assets or liabilities. Prior to and after the acquisition of LG&E's parent, LKE, by PPL, LG&E recovers the cost of these contracts. LG&E's customer rates will continue to reflect these items at their original contracted prices.

In January 2010, LG&E filed an application with the Kentucky Commission requesting annual increases in electric base rates of approximately 12%, or $95 million, and natural gas base rates of approximately 8%, or $23 million. In June 2010, LG&E and all of the intervenors, except the Attorney General of Kentucky, agreed to stipulations providing for annual increases in electric base rates of $74 million and natural gas base rates of $17 million and filed a request with the Kentucky Commission to approve such settlement. An Order in the proceeding was issued in July 2010, approving all the provisions in the stipulations and a return on equity range of 9.75% - 10.75%. The new rates became effective on August 1, 2010.

The following regulatory assets and liabilities are included in the Condensed Balance Sheets:

				March 31, 2011		December 31, 2010

Current regulatory assets:
	ECR(a)			$	5	$	5
	GSC(b)				5		4
	Coal contracts(c)				1		1
	FAC(a)				3		3

Total current regulatory assets				$	14	$	13

Non-current regulatory assets:
	Pension and postretirement benefits(d)			$	213	$	213
	Other non-current regulatory assets:
		Storm restoration(e)			63		65
		Unamortized loss on bonds(e)			22		22
		Mark-to-market impact of interest rate swaps(f)			32		34
		Coal contracts(c)			7		8
		Swap termination(e)			9		9
		ARO(g)			8		7
		Other(h)			8		9

			Subtotal other non-current regulatory assets		149		154

Total non-current regulatory assets				$	362	$	367

Current regulatory liabilities:
	Coal contracts			$	23	$	31
	DSM				6		5
	Emission allowances				5		6
	GSC				4		9

Total current regulatory liabilities				$	38	$	51

Non-current regulatory liabilities:
	Accumulated cost of removal of utility plant			$	279	$	275
	Other non-current regulatory liabilities:
		Coal contracts			85		87
		OVEC power purchase contract			84		86
		Deferred income taxes—net			33		34
		Other(i)			2		1

			Subtotal other non-current regulatory liabilities		204		208

Total non-current regulatory liabilities				$	483	$	483

(b)

The GSC regulatory asset, including PBR, has a separate recovery mechanism with recovery within eighteen months.

(c)

Offsetting regulatory asset for fair value purchase accounting adjustment. See the Company's Financial Statements and Additional Information Report for 2010 for information on the purchase accounting adjustments.

(d)

LG&E recovers this asset through pension and postretirement expenses included in the calculation of base rates.

(e)

These regulatory assets are recovered through base rates.

(f)

Beginning in the third quarter of 2010, based on an Order from the Kentucky Commission in the rate case whereby the cost of a terminated interest rate swap was allowed to be recovered in base rates, the mark-to-market impact of the effective and ineffective interest rate swaps is considered probable of recovery through rates and therefore included in regulatory assets. See Note 4, Derivative Financial Instruments, for further discussion.

(g)

ARO regulatory assets. When an asset with an ARO is retired, the related ARO regulatory asset will be offset against the associated ARO asset and ARO liability.

(h)

Other regulatory assets include:

•: The Carbon Management Research Group and Kentucky Consortium for Carbon Storage contributions, an East Kentucky Power Cooperative FERC transmission settlement agreement, rate case expenses, unamortized debt expense and the MISO exit costs, which are recovered through base rates.
•: Offsetting regulatory asset for fair value purchase accounting adjustment for leases. See the Company's Financial Statements and Additional Information Report for 2010 for information on the purchase accounting adjustments.

(i)

Other regulatory liabilities include the emission allowance purchase accounting offset and MISO exit. See the Company's Financial Statements and Additional Information Report for 2010 for information on the purchase accounting adjustments.

LG&E is subject to interest rate and commodity price risk related to on-going business operations. It currently manages these risks using derivative instruments, including swaps and forward contracts. The Company's policies allow for the interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate swaps. At March 31, 2011, LG&E's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.

LG&E uses over-the-counter interest rate swaps to limit exposure to market fluctuations in interest expense. Pursuant to Company policy, use of these derivative financial instruments is intended to mitigate risk, earnings and cash flow volatility and is not speculative in nature.

LG&E's interest rate swap agreements range in maturity through 2033, with aggregate notional amounts of $179 million as of March 31, 2011 and December 31, 2010. Under these swap agreements, LG&E paid fixed rates averaging 4.52% and received variable rates based on London Interbank Offer Rate or the Securities Industry and Financial Markets Association's municipal swap index. Beginning in the third quarter of 2010, the unrealized gains and losses on the interest rate swaps are included in a regulatory asset based on an Order from the Kentucky Commission in the rate case, whereby the cost of a terminated swap was allowed to be recovered in base rates.

The table below shows the fair value and balance sheet location of interest rate swap derivatives:

The interest rate swaps are accounted for on a fair value basis in accordance with the derivatives and hedging guidance of the FASB ASC. For the three months ended March 31, 2011 and 2010, the impact of the derivative positions on interest rate swaps recorded on the Condensed Statements of Income was not significant.

No gain or loss on hedging interest rate swaps was recognized in other comprehensive income for the period ended March 31, 2011, and the loss recognized was not significant for the period ended March 31, 2010.

Prior to including the unrealized gains and losses on the interest rate swaps in regulatory assets, amounts previously recorded in accumulated other comprehensive income were reclassified into earnings in the same period during which the derivative forecasted transaction affected earnings. The amount included in regulatory assets for the three months ended March 31, 2011 and the amount amortized from accumulated other comprehensive income to earnings for the three months ended March 31, 2010, were not significant.

A decline of 100 basis points in the current market interest rates would increase the fair value of LG&E's interest rate swap liabilities by $27 million.

Assets and liabilities from short-term and long-term energy trading and risk management derivative contracts were not significant at March 31, 2011 and December 31, 2010.

The Company maintains credit policies intended to minimize credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties prior to entering into transactions with them and continuing to evaluate their creditworthiness once transactions have been initiated. To further mitigate credit risk, LG&E seeks to enter into netting agreements or require collateral such as cash deposits, letters of credit or parent company guarantees as security from counterparties. The Company uses credit ratings of S&P, Moody's and definitive qualitative and quantitative data to assess the financial strength of counterparties on an on-going basis. If no external rating exists, LG&E assigns an internally generated rating for which it sets appropriate risk parameters. As risk management contracts are valued based on changes in market prices of the related commodities, credit exposures are revalued and monitored on a daily basis. At March 31, 2011, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better. The Company has reserved against credit risk based on LG&E's own creditworthiness (for net liabilities) and its counterparties' creditworthiness (for net assets). The Company applies historical default rates within varying credit ratings over time provided by S&P or Moody's. At March 31, 2011 and December 31, 2010, credit reserves related to energy trading and risk management contracts were not significant.

The net volume of electricity based financial derivatives outstanding at March 31, 2011 and December 31, 2010, was 1,090,064 Mwh and 869,101 Mwh, respectively. Cash collateral posted by the Company related to the energy trading and risk management contracts was not significant at March 31, 2011 and December 31, 2010. Cash collateral related to the energy trading and risk management contracts is recorded in Prepayments and other current assets on the Condensed Balance Sheets.

LG&E manages the price risk of its estimated future excess economic generation capacity using market-traded forward contracts. Hedge accounting treatment has not been elected for these transactions; therefore, realized and unrealized gains and losses are included on the Condensed Statements of Income. For the three months ended March 31, 2011 and 2010, the impact of the derivative positions on energy trading and risk management activities recorded on the Condensed Statements of Income was not significant.

Certain of LG&E's derivative contracts contain credit contingent provisions which would permit the counterparties with which LG&E is in a net liability position to require the transfer of additional collateral upon a decrease in LG&E's credit rating. Some of these provisions require LG&E to transfer additional collateral or permit the counterparty to terminate the contract if LG&E's credit rating were to fall below investment grade. Some of these provisions also allow the counterparty to require additional collateral upon each decrease in the credit rating at levels that remain above investment grade. In either case, if LG&E's credit rating were to fall below investment grade (i.e., below BBB- for S&P or Baa3 for Moody's) and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent provisions require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization by LG&E on derivative instruments in net liability positions.

Additionally, certain of LG&E's derivative contracts contain credit contingent provisions that require LG&E to provide "adequate assurance" of performance if the other party has reasonable

grounds for insecurity regarding LG&E's performance of its obligation under the contract. A counterparty demanding adequate assurance could require a transfer of additional collateral or other security, including letters of credit, cash and guarantees from a creditworthy entity. A demand for additional assurance would typically involve negotiations among the parties. However, amounts disclosed below represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" provisions.

To determine net liability positions, LG&E uses the fair value of each agreement. The aggregate fair value of all derivative instruments with the credit contingent provisions described above that were in a net liability position at March 31, 2011 was $24 million, of which LG&E had posted collateral of $20 million in the normal course of business. At March 31, 2011, if the credit contingent provisions underlying these derivative instruments were triggered due to a credit downgrade of the Company's credit rating below investment grade, LG&E would have been required to post an additional $4 million of collateral to its counterparties.

The FASB ASC guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. As a basis for considering such assumptions, the FASB ASC guidance establishes a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value.

The fair value of the interest rate swaps reflect price quotes from investment banks, consistent with the fair value measurements and disclosures guidance of the FASB ASC. This value is verified monthly by the Company using a model that calculates the present value of future payments under the swap utilizing current swap market rates obtained from another dealer active in the swap market and validated by market transactions. Market liquidity is considered; however, the valuation does not require an adjustment for market liquidity as the market is very active for the type of swaps used by the Company. LG&E considered the impact of its own credit risk and that of counterparties by evaluating credit ratings and financial information and adjusting market valuations to reflect such credit risks. LG&E and all counterparties had strong investment grade ratings at March 31, 2011. In addition, the Company and certain counterparties have agreed to post margin if the credit exposure exceeds certain thresholds. Cash collateral posted by the Company related to interest rate swaps at March 31, 2011 and December 31, 2010, was $20 million and $19 million, respectively. Cash collateral for interest rate swaps is classified as an Other long-term asset on the Condensed Balance Sheets.

trading and risk management activities occurred during the three months ended March 31, 2011 or 2010. Changes in market pricing, interest rate and volatility assumptions were made during the three months ended March 31, 2011 and 2010.

The fair values of cash and cash equivalents, accounts receivable, accounts payable and notes payable are substantially the same as their carrying values.

The Company classifies its derivative cash collateral balances within Level 1 based on the funds being held in a demand deposit account. The Company classifies its derivative energy trading and risk management contracts and interest rate swaps within Level 2 because it values them using prices actively quoted for proposed or executed transactions, quoted by brokers or observable inputs other than quoted prices.

The following tables set forth, by level within the fair value hierarchy, LG&E's financial assets and liabilities that were accounted for at fair value on a recurring basis.

March 31, 2011			Level 1		Level 2		Totals

Financial assets:
		Cash and cash equivalents	$	28	$	—	$	28
	Energy trading and risk management contract cash collateral			3		—		3
	Interest rate swaps cash collateral			20		—		20
	Other			1		1		2

Total financial assets			$	52	$	1	$	53

Financial liabilities:
	Energy trading and risk management contracts		$	—	$	2	$	2
		Interest rate swaps		—		32		32

Total financial liabilities			$	—	$	34	$	34

December 31, 2010			Level 1		Level 2		Totals

Financial assets:
		Cash and cash equivalents:	$	2	$	—	$	2
	Short-term investments—municipal debt securities			163		—		163
	Energy trading and risk management contract cash collateral			3		—		3
	Interest rate swaps cash collateral			19		—		19

Total financial assets			$	187	$	—	$	187

Financial liabilities:
	Energy trading and risk management contracts		$	—	$	2	$	2
		Interest rate swaps		—		34		34

Total financial liabilities			$	—	$	36	$	36

Financial assets related to energy trading and risk management contracts were not significant at December 31, 2010.

There were no Level 3 measurements for the periods ending March 31, 2011 and December 31, 2010.

The carrying values and estimated fair values of LG&E's non-trading financial instruments follow:

The fair value of these instruments was estimated using an income approach by discounting future cash flows at estimated current cost of funding rates.

employees' labor charges. For the three months ended March 31, 2011 and March 31, 2010, LG&E was allocated approximately 44% and 43% of Servco's costs, respectively.

LG&E made discretionary contributions to its pension plans of $64 million and $20 million in January 2011 and 2010, respectively. In addition, Servco made discretionary contributions to its pension plan of $38 million and $9 million in January 2011 and 2010, respectively. The amount of future contributions to the pension plans will depend upon the actual return on plan assets and other factors, but the Company's intent is to fund its pension plans in a manner consistent with the requirements of the Pension Protection Act of 2006.

For the three months ended March 31, 2011, the Company made contributions to its other postretirement benefit plan of $1 million. The Company anticipates making further voluntary contributions to fund Voluntary Employee Beneficiary Association trusts to match the annual postretirement expense and funding the 401(h) plan up to the maximum tax deductible amount.

Effective January 1, 2011, provisions within Health Care Reform required dependent coverage up to age 26, removed the $2 million lifetime maximum and eliminated the cost sharing for certain preventative care procedures. The impact to LG&E is not expected to be material.

Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. LG&E will not be impacted by this provision.

A provision within Health Care Reform beginning in 2018 is a potential excise tax on high-cost plans providing health coverage that exceeds certain thresholds. The Company has evaluated this provision of Health Care Reform on its benefit programs in consultation with its actuarial consultants and has determined that the excise tax will not have an impact on its postretirement medical plan.

The Company will continue to monitor the potential impact of any changes to the existing provisions and implementation guidance related to Health Care Reform.

LG&E's federal income tax return is included in a U.S. consolidated income tax return filed by LKE's direct parent. Prior to November 1, 2010, the return was included in the consolidated return of E.ON US Investments Corp. Due to the acquisition by PPL, the return will be included in the consolidated PPL return beginning November 1, 2010, for each tax period. Each subsidiary of the consolidated tax group, including LG&E, calculates its separate income tax for each period. The resulting separate-return tax cost or benefit is paid to or received from the parent company or its designee. The Company also files income tax returns in various state jurisdictions. While 2007 and later years are open under the federal statute of limitations, Revenue Agent Reports for 2007-2008 have been received from the Internal Revenue Service ("IRS"), effectively closing these years to additional audit adjustments. Tax years beginning with 2007 were examined under an IRS program, Compliance Assurance Process ("CAP"). This program accelerates the IRS's review to begin during the year applicable to the return and ends 90 days after the return is filed. For 2008, the IRS allowed additional deductions in connection with the Company's application for a change in repair deductions and disallowed certain bonus depreciation claimed on the original return. The net temporary tax impact for the Company was a $13 million reduction in tax and was recorded in the second quarter of 2010. The 2009 federal return was filed in the third quarter of 2010 and the IRS issued a Partial Acceptance Letter in connection with CAP. The IRS is continuing to review storms and other repairs, contributions in aid of construction and purchased natural gas adjustments. No net material adverse impact is expected from these remaining areas. The short tax year beginning January 1, 2010 through October 31, 2010, is also being examined under CAP. No material items have been raised by the IRS at this time. The two month period beginning November 1, 2010 and ending December 31, 2010, is not currently under examination.

		Successor			Predecessor

Reconciliation of Income Taxes		Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
Federal income tax on income before income taxes at statutory tax rate—35%		$	21		$	18
Increase (decrease) due to:
	State income taxes—net of federal income tax benefit		2			2
	Investment and other tax credits		(1	)		(1	)
	Other—net		—			(1	)

Net increase			1			—

Income tax expense		$	22		$	18

Effective income tax rate			36.1	%		35.3	%

LG&E had no material changes in unrecognized tax benefits since December 31, 2010, and does not expect any material changes to occur in unrecognized tax benefits during the next 12 months.

As summarized below, long-term debt consisted of first mortgage bonds and secured pollution control bonds.

In November 2010, LG&E issued first mortgage bonds totaling $535 million and used the proceeds to repay loans from a PPL subsidiary and for general corporate purposes. The first mortgage bonds were issued at a discount.

The first mortgage bonds were issued by LG&E via transactions not requiring registration under the Securities Act of 1933. LG&E entered into a registration rights agreement in which it agreed to file a registration statement with the SEC relating to an offer to exchange the first mortgage bonds for publicly tradable securities having substantially identical terms. If ultimate registration and/or certain milestones are not completed by certain dates in mid- and late 2011, the Company has agreed to pay liquidated damages to the bondholders. The liquidated damages would total 0.25% per annum of the principal amount of the bonds for the first 90 days and 0.50% per annum of the principal amount thereafter until the conditions described above have been cured. In April, 2011, LG&E filed a registration statement on Form S-4 with the SEC, pursuant to the registration rights agreements described above.

At March 31, 2011, LG&E had an aggregate $574 million of outstanding pollution control indebtedness, of which $135 million is in the form of insured auction rate securities wherein interest rates are reset either weekly or every 35 days via an auction process. The credit ratings of the monoline bond insurers have been reduced to levels below that of the Company's rating due to exposures relating to insurance of sub-prime mortgages. As a result, the debt ratings of the Company's insured pollution control bonds are based on the Company's senior secured debt rating and are not influenced by the monoline bond insurer ratings. When a failed auction occurs, the interest rate is set pursuant to a formula stipulated in the indenture.

LG&E's available for sale debt securities, totaling $163 million at December 31, 2010, included certain pollution control bonds, which were repurchased from the remarketing agent in 2008. In January 2011, LG&E remarketed the Louisville/Jefferson County Metro Government 2003 Series A and 2007 Series B bonds, bearing interest at 1.90% into 2012, that were previously held by the Company. The proceeds from the remarketing were used to repay the borrowing under LG&E's credit facility. As of March 31, 2011, LG&E had no remaining repurchased bonds.

See Note 4, Derivative Financial Instruments, for a discussion of the Company's interest rate swap agreements.

As of March 31, 2011, the Company maintained a $400 million revolving line of credit with a group of banks maturing in December 2014. The revolving line of credit allows LG&E to issue letters of credit or borrow funds up to $400 million. Outstanding letters of credit reduce the facility's available borrowing capacity. The Company pays the banks an annual commitment fee based on current bond ratings on the unused portion of the commitment. At March 31, 2011, there were no borrowings outstanding under this facility. This credit agreement contains financial covenants requiring the borrower's debt to total capitalization ratio to not exceed 70%, as calculated pursuant to the credit agreement, and other customary covenants.

LG&E was in compliance with all debt covenants at March 31, 2011 and December 31, 2010.

Except as may be discussed in this quarterly report (including Note 3, Rates and Regulatory Matters), material changes have not occurred in the current status of various commitments or contingent liabilities from that discussed in the LG&E's Financial Statements and Additional Information Report for 2010 (including, but not limited to, Note 10, Related Party Transactions; Note 3, Rates and Regulatory Matters; and Note 11, Subsequent Events; to the financial statements of the Company contained therein).

Pursuant to a power purchase agreement with OVEC, extended in February 2011, to 2040, pending regulatory approvals, the Company may be conditionally responsible for a 5.63% pro-rata share of certain obligations of OVEC under defined circumstances. These contingent liabilities may include unpaid OVEC indebtedness as well as shortfall amounts in certain excess decommissioning costs and postretirement benefits other than pension. LG&E's contingent proportionate share of OVEC's outstanding debt was $77 million at March 31, 2011. See Note 2, Summary of Significant Accounting Policies, for further information.

LG&E is involved in legal proceedings, claims and litigation in the ordinary course of business and cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.

LG&E had approximately $117 million of commitments in connection with its construction program at March 31, 2011.

LG&E's and KU's CCN for a transmission line associated with the TC2 construction has been challenged by certain property owners in Hardin County, Kentucky. Certain proceedings relating to

CCN challenging and federal historic preservation permit requirements have concluded with outcomes in the Utilities' favor.

In July 2009, the FERC issued an order approving LG&E's September 2008 tri-annual application for updated market-based rate authority. During July 2009, affiliates of LG&E completed a transaction terminating certain prior generation and power marketing activities in the Big Rivers Electric Corporation control area, which termination should ultimately allow a filing to request a determination that LG&E is no longer deemed to have market power in such control area and that historical restrictions on LG&E sales into that area is no longer applicable.

IRP regulations require major utilities to make triennial IRP filings with the Kentucky Commission. In April 2011, LG&E and KU filed their 2011 joint IRP with the Kentucky Commission. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information. Impending environmental regulation could result in the retirements of older, smaller coal-fired units and therefore, the IRP assumes potential retirements of approximately 800 megawatts of coal-fired capacity with replacement by combined cycle gas units in 2016. In addition the IRP assumes approximately 500 megawatts of peak demand reductions by 2017, via existing or expanded demand side management or energy efficiency programs. Implementation of the major findings of the IRP is subject to further Company analysis and decision-making and further regulatory approvals.

As a result of the EPAct 2005, certain formerly voluntary reliability standards became mandatory in June 2007 and authority was delegated to various Regional Reliability Organizations ("RROs") by the North American Electric Reliability Corporation ("NERC"), which was authorized by the FERC to enforce compliance with such standards, including promulgating new standards. Failure to comply with mandatory reliability standards can subject a registered entity to sanctions, including potential fines of up to $1 million per day, as well as non-monetary penalties, depending upon the circumstances of the violation. The Utilities are members of the SERC Reliability Corporation ("SERC"), which acts as

their RRO. The Utilities have continued to self-report potential violations of certain applicable reliability requirements and submit accompanying mitigation plans. The resolution of a number of these potential violation reports is pending. Any regional reliability entity determination concerning resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC. Therefore, the Utilities are unable to estimate the outcome of these matters. Additionally, the Utilities have one open self-report which has been the subject of a settlement with the SERC. This settlement was for no penalty but still requires FERC approval before becoming final. Mandatory reliability standard settlements commonly also include non-penalty elements, including compliance steps and mitigation plans. While the Utilities believe they are in compliance with the mandatory reliability standards, events of potential non-compliance may be identified from time-to-time. The Utilities cannot predict such potential violations or the outcome of self-reports described above.

In February 2006, the Kentucky Commission initiated an administrative proceeding to consider the requirements of the federal EPAct 2005, Subtitle E Section 1252, Smart Metering, which concerns time-based metering and demand response, and Section 1254, Interconnections. The EPAct 2005 requires each state regulatory authority to conduct a formal investigation and issue a decision on whether or not it is appropriate to implement certain Section 1252 standards within eighteen months after the enactment of the EPAct 2005 and to commence consideration of Section 1254 standards within a year after the enactment of the EPAct 2005. Following a public hearing with all Kentucky jurisdictional electric utilities, in December 2006, the Kentucky Commission issued an Order in this proceeding indicating that the EPAct 2005 Section 1252 and Section 1254 standards should not be adopted. However, all the Kentucky Commission jurisdictional utilities are required to file real-time pricing pilot programs for their large commercial and industrial customers. LG&E and KU developed real-time pricing pilots for large industrial and commercial customers and filed the details of the plan with the Kentucky Commission in April 2007. In February 2008, the Kentucky Commission issued an Order approving the real-time pricing pilot programs proposed by LG&E and KU for implementation for their large commercial and industrial customers. The tariff was filed in October 2008, with an effective date of December 1, 2008. LG&E and KU file annual reports on the program within 90 days of each plan year-end for the three-year pilot period.

Pursuant to a 2004 rate case settlement agreement, and as referred to in the EPAct 2005 Administrative Order, LG&E made its responsive pricing and smart metering pilot program filing, which addresses real-time pricing for residential and general service customers, in March 2007. In July 2007, the Kentucky Commission approved the application, as filed, for a small number of residential customers and a sampling of other customers, and authorized LG&E to establish the responsive pricing and smart metering pilot program, recovery of non-specific customer costs through the DSM billing mechanism and the filing of annual reports by April 1, 2009, 2010 and 2011. LG&E must also file an evaluation of the program by July 1, 2011.

The Company's operations are subject to a number of environmental laws and regulations governing, among other things, air emissions, wastewater discharges, the use, handling and disposal of

hazardous substances and wastes, soil and groundwater contamination and employee health and safety. As indicated below and summarized at the conclusion of this section, evolving environmental regulations will likely increase the level of capital and operating and maintenance expenditures incurred by the Company during the next several years. Based upon prior regulatory precedent, the Company believes that many costs of complying with such pending or future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but the Company can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

From time to time, LG&E appears before the EPA, various state or local regulatory agencies and state and federal courts regarding matters involving compliance with applicable environmental laws and regulations. Such matters include a prior Section 114 information request from the EPA relating to new source review issues at LG&E's Mill Creek Unit 4 and Trimble County Unit 1; remediation obligations or activities for former manufactured gas plant sites or other risks relating to elevated PCB levels at existing properties; liability under the Comprehensive Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; and on-going claims regarding alleged particulate emissions from the Company's Cane Run generating station and claims regarding GHG emissions from the Company's generating stations. Based on analysis to date, the resolution of these matters is not expected to have a material impact on the Company's operations.

In 1997, the EPA established new NAAQS for ozone and fine particulates that required additional reductions in SO₂ and NOx emissions from power plants. In 1998, the EPA issued its final "NOx SIP Call" rule requiring reductions in NOx emissions of approximately 85% from 1990 levels in order to mitigate ozone transport from the midwestern U.S. to the northeastern U.S. To implement the new federal requirements, Kentucky amended its SIP in 2002 to require electric generating units to reduce their NOx emissions to 0.15 pounds weight per million British thermal units on a company-wide basis. In 2005, the EPA issued the CAIR which required additional SO₂ emission reductions of 70% and NOx emission reductions of 65% from 2003 levels. The CAIR provided for a two-phase cap and trade program, with initial reductions of NOx and SO₂ emissions due by 2009 and 2010, respectively, and final reductions due by 2015. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAIR.

In January 2010, the EPA proposed a revised NAAQS for ozone which would increase the stringency of the standard. In addition, the EPA published final revised NAAQS standards for NO₂ and SO₂ in February 2010 and June 2010, respectively, which are more stringent than previous standards. Depending on the level of action determined necessary to bring local nonattainment areas into compliance with the revised NAAQS standards, LG&E's power plants are potentially subject to requirements for additional reductions in SO₂ and NOx emissions.

In February 2008, a federal appellate court issued a decision vacating the CAMR. In March 2011, the EPA released the proposed utility Maximum Achievable Control Technology rule to replace the CAMR. The proposed rule would establish standards for hazardous air pollutants emitted by power plants including mercury, other heavy metals, and acid gases. The emissions limitations specified in the proposed rule are stringent, requiring a 91% reduction in the case of mercury emissions. Upon promulgation of a final rule, facilities would have a short three-year period to comply with the new requirements, with the possibility of a one-year extension from the state. The Company will be unable

to determine the exact impact on Company operations until such time as a final rule is promulgated by the EPA.

The Clean Air Act also includes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing future impairment and remedying any existing impairment of visibility in those areas. In 2005, the EPA issued its Clean Air Visibility Rule detailing how the Clean Air Act's BART requirements will be applied to facilities, including power plants built between 1962 and 1974 that emit certain levels of visibility impairing pollutants. Under the final rule, as the CAIR provided for more visibility improvement than BART, states are allowed to substitute CAIR requirements in their regional haze SIPs in lieu of controls that would otherwise be required by BART. The final rule has been challenged in the courts. Additionally, because the regional haze SIPs incorporate certain CAIR requirements, the remand of the CAIR could potentially impact regional haze SIPs. See Ambient Air Quality above for a discussion of CAIR-related uncertainties.

LG&E submitted an analysis of the visibility impacts of its Kentucky BART-eligible sources to the KDAQ. Only LG&E's Mill Creek plant was determined to have a significant regional haze impact. The KDAQ has submitted a regional haze SIP to the EPA which requires the Mill Creek plant to reduce its sulfuric acid mist emissions from Units 3 and 4. After approval of the Kentucky SIP by the EPA and revision of the Mill Creek plant's Title V air permit, sorbent injection controls will be installed at the plant to reduce sulfuric acid mist emissions.

monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner. LG&E expects to incur additional capital expenditures currently approved in its ECR plans totaling approximately $100 million during the 2011 through 2013 time period to achieve emissions reductions and manage coal combustion residuals. Monthly recovery is subject to periodic review by the Kentucky Commission.

The Sierra Club and other environmental groups filed a petition challenging the air permit issued for the TC2 baseload generating unit which was issued by the KDAQ in November 2005. In September 2007, the Secretary of the Kentucky Environmental and Public Protection Cabinet issued a final Order upholding the permit. The environmental groups petitioned the EPA to object to the state permit and subsequent permit revisions. In determinations made in September 2008 and June 2009, the EPA rejected most of the environmental groups' claims but identified three permit deficiencies which the KDAQ addressed by revising the permit. In August 2009, the EPA issued an Order denying the remaining claims with the exception of two additional deficiencies which the KDAQ was directed to address. The EPA determined that the proposed permit subsequently issued by the KDAQ satisfied the conditions of the EPA Order although the agency recommended certain enhancements to the administrative record. In January 2010, the KDAQ issued a final permit revision incorporating the proposed changes to address the two EPA objections. In March 2010, the Sierra Club submitted a petition to the EPA to object to the permit revision, which is now pending before the EPA. The Company believes that the final permit as revised should not have a material adverse effect on its financial condition or results of operations. However, until the EPA issues a final ruling on the pending petition and all applicable appeals have been exhausted, the Company cannot predict the final outcome of this matter.

In 2005, the Kyoto Protocol for reducing GHG emissions took effect, obligating 37 industrialized countries to undertake substantial reductions in GHG emissions. The U.S. has not ratified the Kyoto Protocol and there are currently no mandatory GHG emission reduction requirements at the federal level. As discussed below, legislation mandating GHG reductions has been introduced in the Congress, but no federal legislation has been enacted to date. In the absence of a program at the federal level, various states have adopted their own GHG emission reduction programs, including 11 northeastern U.S. states and the District of Columbia under the Regional GHG Initiative program and California. Substantial efforts to pass federal GHG legislation are on-going. The current administration has announced its support for the adoption of mandatory GHG reduction requirements at the federal level. The United States and other countries met in Copenhagen, Denmark, in December 2009, in an effort to negotiate a GHG reduction treaty to succeed the Kyoto Protocol, which is set to expire in 2013. In Copenhagen, the U.S. made a nonbinding commitment to, among other things, seek to reduce GHG emissions to 17% below 2005 levels by 2020 and provide financial support to developing countries. The United States and other nations met in Cancun, Mexico, in December 2010 to continue negotiations toward a binding agreement.

In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG under the Clean Air Act. In April 2009, the EPA issued a proposed endangerment finding concluding that GHGs endanger public health and welfare, which is an initial rulemaking step under the Clean Air Act. A final endangerment finding was issued in December 2009. In September 2009, the EPA issued a final GHG reporting rule requiring reporting by facilities with annual GHG emissions equivalent to at least 25,000 tons of carbon dioxide. A number of the Company's facilities are required to submit annual reports commencing with calendar year 2010. In May 2010, the EPA issued a final GHG "tailoring" rule, effective January 2011, requiring new or modified sources with GHG emissions equivalent to at least 75,000 tons of carbon dioxide to obtain permits under the Prevention of Significant Deterioration Program. Such new or modified facilities would be required to install Best Available Control Technology. While the Company is unaware of any currently available GHG control technology that might be required for installation on new or modified power plants, it is currently assessing the potential impact of the rule. The final rule will apply to new and modified power plants beginning in January 2011. The Company is unable to predict whether mandatory GHG reduction requirements will ultimately be enacted through legislation or regulations. In December 2010, the EPA announced that it plans to promulgate GHG New Source Performance Standards for power plants, including both new and existing facilities. A proposed rule is expected by July 2011, while a final rule is expected by May 2012. In the absence of either a proposed or final regulation, LG&E is unable to assess the potential impact of any future regulation.

A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting facilities. In October 2009, a three-judge panel of the United States Court of Appeals for the 5^th Circuit in the case of Comer v. Murphy Oil reversed a lower court, holding that private plaintiffs have standing to assert certain common law claims against more than 30 utility, oil, coal and chemical companies. In March 2010, the court vacated the opinion of the three-judge panel and granted a motion for rehearing but subsequently denied the appeal due to the lack of a quorum. The appellate ruling leaves in effect the lower court ruling dismissing the plaintiffs' claims. In January 2011, the Supreme Court denied petitioner's petition for review, which effectively brings the case to an end. The Comer complaint alleged that GHG emissions from the defendants' facilities contributed to global warming which increased the intensity of Hurricane Katrina. E.ON AG, the former indirect parent of the Utilities, was named as a defendant in the complaint, but was not a party to the proceedings due to the failure of the plaintiffs to pursue service under the applicable international procedures. LG&E continues to monitor relevant GHG litigation to identify judicial developments that may be potentially relevant to operations.

The EPA has undertaken various initiatives in response to the December 2008 impoundment failure at the Tennessee Valley Authority's Kingston power plant, which resulted in a major release of coal combustion byproducts into the environment. The EPA issued information requests to utilities throughout the country, including LG&E, to obtain information on their ash ponds and other impoundments. In addition, the EPA inspected a large number of impoundments located at power plants to determine their structural integrity. The inspections included several of LG&E's impoundments, which the EPA found to be in satisfactory condition except for certain impoundments at the Mill Creek and Cane Run stations, which were determined to be in fair condition. In June 2010, the EPA published proposed regulations for coal combustion byproducts handled in landfills and ash ponds. The EPA has proposed two alternatives: (1) regulation of coal combustion byproducts in landfills and ash ponds as a hazardous waste or (2) regulation of coal combustion byproducts as a solid waste with minimum national standards. Under both alternatives, the EPA has proposed safety requirements to address the structural integrity of ash ponds. In addition, the EPA will consider potential refinements of the provisions for beneficial reuse of coal combustion byproducts.

In March 2011, the EPA released a proposed cooling water intake structure rule pursuant to Section 316(b) of the Clean Water Act. The proposed rule would require a case-by-case review to identify appropriate measures to mitigate the impact of cooling water intake structures on aquatic life. Mitigation measures required as a result of the review could range from use of smaller mesh screens on intake structures to more costly measures such as construction of cooling towers. The exact impact of the rule will depend on the provisions contained in the final rule promulgated by the EPA and the subsequent implementation of the rule by the states. The EPA has also announced plans to develop revised effluent limitation guidelines governing discharges from power plants. The EPA has further

announced plans to develop revised standards governing the use of PCB in electrical equipment. The Company is monitoring these ongoing regulatory developments, but will be unable to determine the impact until such time as new rules are finalized.

Seepages or groundwater infiltration has been detected at wastewater basins or landfills at various LG&E plants. LG&E has completed or is completing assessments of seepages at various facilities and is working with agencies to implement abatement measures for those seepages, where required. The potential cost to address identified seepages or other seepages at LG&E plants is not now determinable, but could be significant.

LG&E is a potentially responsible party at several sites listed by the EPA under the federal Superfund program. Clean-up actions have been or are being undertaken at all of these sites, the costs of which has not been significant to the Company. However, should the EPA require different or additional measures in the future, or should LG&E's share of costs at multi-party sites increase significantly more than currently expected, the costs to LG&E could be significant.

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

Depending on the outcome of investigations at sites where investigations have not begun or been completed or developments at sites for which the Company currently lacks information, the costs of remediation and other liabilities could be substantial. It also could incur other non-remediation costs at sites included in current consent orders or other contaminated sites, the costs of which are not now determinable but could be significant.

As a company with significant coal-fired generating assets, LG&E will likely be substantially impacted by pending or future environmental rules or legislation requiring mandatory reductions in

GHG emissions or other air emissions, imposing more stringent standards on discharges to waterways, or establishing additional requirements for handling or disposal of coal combustion byproducts. These evolving environmental regulations will likely require an increased level of capital expenditures and increased incremental operating and maintenance costs by the Company over the next several years. Due to the uncertain nature of the final regulations that will ultimately be adopted by the EPA, including the reduction targets and the deadlines that will be applicable, the Company cannot finalize estimates of the potential compliance costs, but should the final rules incorporate additional emission reduction requirements, require more stringent emissions controls or implement more stringent byproducts storage and disposal practices, such costs will likely be significant. With respect to NAAQS, CATR, utility Maximum Achievable Control Technology rule and coal combustion byproducts developments, based upon a preliminary analysis of proposed regulations, the Company may be required to consider actions such as upgrading existing emissions controls, installing additional emissions controls, upgrading byproducts disposal and storage and possible early replacement of coal-fired units. Capital expenditures for LG&E associated with such actions are preliminarily estimated to be in the $1.75 to $2.0 billion range over the next ten years, although final costs may substantially vary. With respect to potential developments in water discharge, including the recently proposed Section 316(b) cooling water intake rule and the expected revisions to the effluent guidelines, revised PCB standards or GHG initiatives, costs in such areas cannot be estimated due to the preliminary status or uncertain outcome of such developments, but would be in addition to the above amount and could be substantial. Ultimately, the precise impact on the Company's operations of these various environmental developments cannot be determined prior to the finalization of such requirements. Based upon prior regulatory precedent, the Company believes that many costs of complying with such pending or future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but the Company can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

LG&E and subsidiaries of LKE and PPL engage in related party transactions. Transactions between LG&E and LKE subsidiaries are eliminated on consolidation of LKE. Transactions between LG&E and PPL subsidiaries are eliminated on consolidation of PPL. These transactions are generally performed at cost and are in accordance with FERC regulations under the Public Utility Holding Company Act of 2005 and the applicable Kentucky Commission regulations.

LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load. When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E. When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU. These transactions are recorded as intercompany wholesale sales and purchases and are recorded by each company at a price equal to the seller's fuel cost. Savings realized from purchasing electricity intercompany instead of generating from their own higher costs units or purchasing from the market are shared equally between the Utilities.

The volume of energy each company has to sell to the other is dependent on its native load needs and its available generation.

These sales and purchases are included in the Condensed Statements of Income as Wholesale to affiliate, and Power purchased from affiliate. LG&E's intercompany electric revenues and power purchased expenses were as follows:

See Note 8, Debt, for details of intercompany borrowing arrangements. Intercompany agreements do not require interest payments for receivables related to services provided when settled within 30 days.

Interest paid to LKE on the money pool arrangement was not significant for the three months ended March 31, 2011 and for the three months ended March 31, 2010. There were no loans from Fidelia Corporation ("Fidelia"), an E.ON AG affiliate, or PPL during the three months ended March 31, 2011. Interest expense related to loans from Fidelia was $7 million for the three months ended March 31, 2010.

In March 2011, the Company paid dividends of $17 million to its sole shareholder, LKE. In March 2010, the Company also paid dividends of $30 million to LKE.

Subsequent events have been evaluated through May 9, 2011, the date of issuance of these statements, and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

On May 2, 2011, LG&E filed a notice of intent to file an ECR plan with the Kentucky Commission. The plan will be filed on or after June 1, 2011.

On April 22, 2011, LG&E filed a Form S-4, Registration Statement, with the SEC, as agreed in its first mortgage bonds registration rights agreement. The Form S-4 relates to an offer to exchange the first mortgage bonds with registered, publicly tradable securities.

On April 21, 2011, LG&E and KU filed their 2011 joint IRP with the Kentucky Commission.

1.625% First Mortgage Bonds due 2015 and
5.125% First Mortgage Bonds due 2040, respectively

	Increase (Decrease)

Base rate price variance(a)	$	16
Demand revenue(b)		8
Wholesale sales volume(c)		8
Sales to KU		3
FAC price variance		2
Retail sales volumes(d)		(6	)
ECR revenue		(4	)
Financial swaps		(3	)

	$	24

	Increase (Decrease)

Distribution maintenance(a)	$	2
Fuel for generation(b)		2
Workers' compensation		2
Steam maintenance		(2	)
Other		3

	$	7

	Change in Assumption	Impact on ARO Liability

		(in millions)
Retirement cost	10%/(10)%	$3/$(3)
Discount rate	0.25%/(0.25)%	$(2)/$2
Inflation rate	0.25%/(0.25)%	$2/$(2)



	Successor				Predecessor
	November 1, 2010 through December 31, 2010				January 1, 2010 through October 31, 2010				Year Ended December 31, 2009				Year Ended December 31, 2008
	Revenues		Volumes (Gwh)		Revenues		Volumes (Gwh)		Revenues		Volumes (Gwh)		Revenues		Volumes (Gwh)
Residential	$	57		682	$	309		3,910	$	310		4,096	$	301		4,206
Industrial and commercial		70		1,024		351		5,372		377		6,029		387		6,574
Other retail		17		209		87		1,141		89		1,280		82		1,303
Wholesale		25		1,107		99		4,138		142		5,711		246		7,884

	$	169		3,022	$	846		14,561	$	918		17,116	$	1,016		19,967



	Successor				Predecessor
	November 1, 2010 through December 31, 2010				January 1, 2010 through October 31, 2010				Year Ended December 31, 2009				Year Ended December 31, 2008
	Revenues		Volumes (MMcf)		Revenues		Volumes (MMcf)		Revenues		Volumes (MMcf)		Revenues		Volumes (MMcf)
Residential	$	56		6,583	$	137		14,424	$	230		19,742	$	281		21,338
Industrial and commercial		22		2,903		58		7,319		98		9,600		136		10,914
Other retail		5		490		11		1,097		20		1,568		23		1,677
Wholesale		2		2,614		5		8,719		6		10,866		12		12,241

	$	85		12,590	$	211		31,559	$	354		41,776	$	452		46,170


Summary		1
Risk Factors		11
A Warning about Forward-Looking Statements		18
Use of Proceeds		20
Capitalization		21
Selected Financial Data		22
Management's Discussion and Analysis of Financial Condition and Results of Operations		23
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		56
Quantitative and Qualitative Disclosures about Market Risk		56
Business		57
Management		71
Executive Compensation		73
Transactions with Related Persons		108
The Exchange Offers		109
Description of the Exchange Bonds		121
Material U.S. Federal Income Tax Consequences		138
Plan of Distribution		143
Legal Matters		143
Experts		143
Available Information		144
Index to Financial Statements		145

	As of March 31, 2011

	(in millions)
Cash and cash equivalents	$	28

Long-term debt, including current portion	$	1,109
Total equity		1,743

Total capitalization	$	2,852

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Electric	$	97		$	(98	)
Natural gas		(58	)		(98	)

	$	39		$	(196	)

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Reduction in natural gas prices billed through gas supply clause, or GSC	$	(82	)	$	(76	)
Retail sales volumes(a)		13			(35	)
Retail base rates price variance(b)		10			16
Off-system wholesale sales due to lower demand		—			(6	)
Other		1			3

	$	(58	)	$	(98	)

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Commodity costs for coal and natural gas	$	23		$	2
Fuel usage volumes(a)		17			(20	)
Other		(2	)		—

	$	38		$	(18	)

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Purchases from KU due to volume(a)	$	(7	)	$	(60	)
Purchases from KU due to prices		(1	)		—
Prices for purchases used to serve retail customers		3			(2	)
Demand payments for third party purchases		1			2
Third party purchased volumes for native load		—			(1	)

	$	(4	)	$	(61	)

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Cost of natural gas supply billed to customers due to lower cost per thousand cubic feet, or Mcf	$	(95	)	$	(73	)
Natural gas volumes delivered		13			(26	)
Wholesale sales of purchased natural gas volumes		—			(5	)
Other		1			—

	$	(81	)	$	(104	)

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Administrative and general expense	$	2		$	2
Bad debt expense		2			—
DSM program spending		2			10
Transmission expense		2			(3	)
Distribution expense		2			(1	)
Power supply expense		1			(4	)
Pension expense(a)		(4	)		24
Other		1			—

	$	8		$	28

	Increase (Decrease)

	2010 vs. 2009		2009 vs. 2008
Steam expense(a)	$	9	$	3
Generation expense(b)		3		—
Administrative and general expense		2		1
Distribution expense		1		(2	)

	$	15	$	2

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Reclassification of ineffective interest rate swap loss to a regulatory asset in 2010 (a)	$	21		$	—
Reclassification of terminated interest rate swap loss to a regulatory asset in 2010 (a)		9			—
Interest expense related to interest rate swaps		2			(2	)
Gain (loss) on interest rate swap		(31	)		57

	$	1		$	55

	Increase (Decrease)

	2010 vs. 2009			2009 vs. 2008
Bond interest expense(a)	$	2		$	(4	)
Interest rate swaps(b)		1			(8	)
Interest expense to affiliated companies(c)		(4	)		(2	)
Other interest expense		3			—

	$	2		$	(14	)

		Issuances(a)		Retirements

Short-term borrowings from affiliated company—net change		$	—	$	(158	)
Other borrowings from affiliated company			485		(485	)
Borrowings from an E.ON affiliate			—		(485	)
Issuance of short-term note payable			163		—
Issuance of bonds			531		—

	Net change in debt financing	$	1,179	$	(1,128	)

		Successor			Predecessor

		Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
Operating income(a)		$	73		$	64
Adjustments:
	Other operation and maintenance expenses(a)		94			87
	Depreciation and amortization(a)		36			34
	Net adjustments(b)		(11	)		(14	)

Margin(c)		$	192		$	171

	Increase (Decrease)

Change in classification(a)	$	25
Retail base rates price variance(b)		5
Wholesale sales		2
GSC revenue(c)		(16	)
Retail sales volumes(d)		(8	)

	$	8

	Increase (Decrease)

Change in classification(a)	$	25
Wholesale sales of natural gas volumes		2
Lower purchase volumes of natural gas delivered to the distribution system		(10	)
Lower prices of natural gas delivered to the distribution system		(10	)
Other		1

	$	8

	March 31, 2011		December 31, 2010

Cash and cash equivalents	$	28	$	2
Available for sale debt securities(a)		—		163

	$	28	$	165

Notes payable to affiliated company(b)	$	—	$	12
Note payable(c)		—		163

	$	—	$	175

	Total Target Direct Compensation(1)

Name	Base Salary (%)		Short-Term Incentive Target (%)		Long-Term Incentive Target (%)
Victor A. Staffieri Chief Executive Officer		29		21		50
S. Bradford Rives Chief Financial Officer		43		22		35
John R. McCall EVP, General Counsel, Corporate Secretary and Chief Compliance Officer		40		20		40
Chris Hermann SVP Energy Delivery		48		24		28
Paul W. Thompson SVP Energy Services		43		22		35

Name

Victor A. Staffieri	30.33	42.6	15	40	127.93
S. Bradford Rives	30.33	42.6	15	56	143.93
John R. McCall	30.33	42.6	15	56	143.93
Chris Hermann	30.33	42.6	15	54	141.93
Paul W. Thompson	30.33	42.6	15	56	143.93

	Targets as a % of Base Salary

	E.ON Share Performance Rights			LG&E Energy Corp. Performance Units			Total
Victor A. Staffieri		43.75	%		131.25	%		175	%
S. Bradford Rives		20	%		60	%		80	%
John R. McCall		25	%		75	%		100	%
Chris Hermann		15	%		45	%		60	%
Paul W. Thompson		20	%		60	%		80	%

	E.ON AG Share Performance Rights(1)		LG&E Energy Performance Units		Total

Victor A. Staffieri	$	357,983	$	1,182,808	$	1,540,791
S. Bradford Rives	$	81,121	$	268,036	$	349,157
John R. McCall	$	124,305	$	410,728	$	535,033
Chris Hermann	$	47,758	$	158,186	$	205,944
Paul W. Thompson	$	75,740	$	250,186	$	325,926

	E.ON AG Share Performance Rights(1)		LG&E Energy Performance Units(2)		Total

Victor A. Staffieri	$	282,761	$	3,745,493	$	4,028,254
S. Bradford Rives	$	64,674	$	857,536	$	922,210
John R. McCall	$	99,121	$	1,313,886	$	1,413,007
Chris Hermann	$	38,172	$	506,126	$	544,298
Paul W. Thompson	$	60,382	$	800,424	$	860,806

Name

Victor A. Staffieri	354,909	1,419,635	2,129,453	2,129,453
S. Bradford Rives	155,400	621,600	932,400	932,400
John R. McCall	190,463	761,850	1,142,775	1,142,775
Chris Hermann	122,288	489,150	733,725	733,725
Paul W. Thompson	145,050	580,200	870,300	870,300

Name

Staffieri	85,409	118,043	79,309	1,242,180	1,242,180	1,261,132
Rives	19,947	26,764	17,963	290,080	281,610	285,846
McCall	30,557	41,006	27,558	444,413	431,463	438,011
Hermann	11,774	15,802	10,596	171,203	166,215	168,708
Thompson	18,618	24,984	16,780	270,760	262,850	266,814

	Stock Awards

Name (a)	Number of Shares or Units of Stock That Have Not Vested (#) (g)(1)		Market Value of Shares or Units of Stock That Have Not Vested ($) (h)(2)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (i)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (j)
Staffieri		80,940		2,130,341		0		0
Rives		23,630		621,942		0		0
McCall		28,960		762,227		0		0
Hermann		18,590		489,289		0		0
Thompson		22,050		580,356		0		0

	Option Awards				Stock Awards

Name (a)	Number of Shares Acquired on Exercise (#) (b)		Value Realized on Exercise ($) (c)		Number of Shares Acquired on Vesting (#) (d)(1)		Value Realized on Vesting ($) (e)(2)
Staffieri		0		0		22,885		640,744
Rives		0		0		5,248		145,795
McCall		0		0		8,041		223,426
Hermann		0		0		3,097		85,930
Thompson		0		0		4,899		136,122

Age

61	96.00	%
60	92.00	%
59	86.56	%
58	81.60	%
57	77.04	%
56	72.96	%
55	69.20	%
54	65.20	%
53	61.20	%
52	57.20	%

Name

Staffieri(1)	8,825,464	6,703,996	6,220,019
Rives(2)	2,331,425	1,880,181	1,626,046
McCall(3)	4,960,680	2,602,451	4,960,680
Hermann(4)	2,283,282	1,218,074	1,967,861
Thompson(5)	2,537,610	2,116,113	1,572,400


By Mail, Hand or Courier		By Facsimile Transmission (eligible institutions only)
The Bank of New York Mellon c/o The Bank of New York Mellon Corporation		(212) 298-1915
Corporate Trust—Reorganization Unit 480 Washington Boulevard—27th Floor		To Confirm by Telephone
Jersey City, New Jersey 07310 Attn: William Buckley—Processor		(212) 815-5788


Report of Independent Registered Public Accounting Firm			F-1
Statements of Income			F-3
Statements of Retained Earnings (Deficit)			F-4
Statements of Comprehensive Income (Loss)			F-5
Balance Sheets			F-6
Statements of Cash Flows			F-8
Statements of Capitalization			F-10
Notes to Financial Statements			F-11



Condensed Statements of Income		F-86
Condensed Statements of Comprehensive Income		F-87
Condensed Statements of Common Equity		F-88
Condensed Balance Sheets		F-89
Condensed Statements of Cash Flows		F-91
Notes to Financial Statements		F-92